83 FR 9636 - Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response
DEPARTMENT OF ENERGY Federal Energy Regulatory Commission
Federal Register Volume 83, Issue 44 (March 6, 2018)
Page Range
9636-9677
FR Document
2018-03707
The Federal Energy Regulatory Commission (Commission) is modifying the pro forma Large Generator Interconnection Agreement (LGIA) and pro forma Small Generator Interconnection Agreement (SGIA) to require newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. These changes are designed to address the potential reliability impact of the evolving generation resource mix, and to ensure that the relevant provisions of the pro forma LGIA and pro forma SGIA are just, reasonable, and not unduly discriminatory or preferential.
Federal Register, Volume 83 Issue 44 (Tuesday, March 6, 2018)
[Federal Register Volume 83, Number 44 (Tuesday, March 6, 2018)]
[Rules and Regulations]
[Pages 9636-9677]
From the Federal Register Online [www.thefederalregister.org]
[FR Doc No: 2018-03707]
[[Page 9635]]
Vol. 83
Tuesday,
No. 44
March 6, 2018
Part III
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Essential Reliability Services and the Evolving Bulk-Power System--
Primary Frequency Response; Final Rule
Federal Register / Vol. 83 , No. 44 / Tuesday, March 6, 2018 / Rules
and Regulations
[[Page 9636]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM16-6-000; Order No. 842]
Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final action.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
modifying the pro forma Large Generator Interconnection Agreement
(LGIA) and pro forma Small Generator Interconnection Agreement (SGIA)
to require newly interconnecting large and small generating facilities,
both synchronous and non-synchronous, to install, maintain, and operate
equipment capable of providing primary frequency response as a
condition of interconnection. These changes are designed to address the
potential reliability impact of the evolving generation resource mix,
and to ensure that the relevant provisions of the pro forma LGIA and
pro forma SGIA are just, reasonable, and not unduly discriminatory or
preferential.
DATES: This final action will become effective May 15, 2018.
FOR FURTHER INFORMATION CONTACT:
Jomo Richardson (Technical Information), Office of Electric
Reliability, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426, (202) 502-6281, [email protected].
Mark Bennett (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, (202) 502-8524, [email protected].
SUPPLEMENTARY INFORMATION:
Order No. 842
Final Action
(Issued February 15, 2018)
Table of Contents
I. Background........................................ 4
A. Frequency Response............................ 4
B. Prior Commission Actions...................... 9
C. Notice of Inquiry............................. 10
D. Notice of Proposed Rulemaking................. 13
E. Notice of Request for Supplemental Comments... 16
II. Discussion....................................... 19
A. Requirement To Install, Maintain, and Operate 28
Equipment Capable of Providing Primary Frequency
Response........................................
1. NOPR Proposal............................. 28
2. Comments.................................. 29
3. Commission Determination.................. 33
B. Including Operating Requirements for Droop and 40
Deadband in the Pro Forma LGIA and Pro Forma
SGIA............................................
1. NOPR Proposal............................. 40
2. Comments.................................. 43
3. Commission Determination.................. 56
C. Requirement To Ensure the Timely and Sustained 86
Response to Frequency Deviations................
1. NOPR Proposal............................. 86
2. Comments.................................. 88
3. Commission Determination.................. 94
D. Proposal Not To Mandate Headroom.............. 106
1. NOPR Proposal............................. 106
2. Comments.................................. 107
3. Commission Determination.................. 109
E. Proposal Not To Mandate Compensation.......... 111
1. NOPR Proposal............................. 111
2. Comments.................................. 112
3. Commission Determination.................. 119
F. Application to Existing Generating Facilities 126
That Submit New Interconnection Requests That
Result in an Executed or Unexecuted
Interconnection Agreement.......................
1. NOPR Proposal............................. 126
2. Comments.................................. 127
3. Commission Determination.................. 131
G. Application to Existing Generating Facilities 135
That Do Not Submit New Interconnection Requests
That Result in an Executed or Unexecuted
Interconnection Agreement.......................
1. NOPR Proposal............................. 135
2. Comments.................................. 136
3. Commission Determination.................. 142
H. Requests for Exemption or Special 147
Accommodation...................................
1. Combined Heat and Power Facilities........ 147
2. Electric Storage Resources................ 156
3. Distributed Energy Resources.............. 189
4. Nuclear Generating Facilities............. 197
5. Wind Generating Facilities................ 203
6. Surplus Interconnection................... 207
7. Small Generating Facilities............... 210
8. Requests To Establish a Waiver Process and 224
Consider Potential Impact on Load and New
Technology..................................
I. Regional Flexibility.......................... 231
1. NOPR Proposal............................. 231
2. Comments.................................. 232
3. Commission Determination.................. 233
J. Miscellaneous Comments........................ 235
1. Uniform System of Accounts................ 235
2. Capability of Load To Provide Primary 237
Frequency Response..........................
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3. Primary Frequency Response Obligations and 239
Pools.......................................
K. Specific Revisions to the Pro Forma LGIA and 241
Pro Forma SGIA..................................
1. NOPR Proposal............................. 241
2. Comments.................................. 242
3. Commission Determination.................. 243
III. Compliance and Implementation................... 250
IV. Information Collection Statement................. 255
V. Regulatory Flexibility Act........................ 262
VI. Environmental Analysis........................... 266
VII. Document Availability........................... 268
VIII. Effective Date and Congressional Notification.. 271
I. Appendix A: List of Substantive NOPR Commenters
(RM16-6-000)
II. Appendix B: List of Substantive Supplemental
Commenters (RM16-6-000)
III. Appendix C: Uniform System of Accounts
162 FERC ] 61,128
United States of America
Federal Energy Regulatory Commission
Before Commissioners: Kevin J. McIntyre, Chairman; Cheryl A.
LaFleur, Neil Chatterjee, Robert F. Powelson, and Richard Glick.
Essential Reliability Services and the Evolving Bulk-Power System--
Primary Frequency Response--Docket No. RM16-6-000
Order No. 842
Final Action
(Issued February 15, 2018)
1. In this final action, the Commission modifies the pro forma
Large Generator Interconnection Agreement (LGIA) and the pro forma
Small Generator Interconnection Agreement (SGIA), pursuant to its
authority under section 206 of the Federal Power Act (FPA), to ensure
that rates, terms and conditions of jurisdictional service remain just
and reasonable and not unduly discriminatory or preferential.\1\ The
modifications require new large and small generating facilities,
including both synchronous and non-synchronous, interconnecting through
a LGIA or SGIA to install, maintain, and operate equipment capable of
providing primary frequency response as a condition of interconnection.
The Commission also establishes certain uniform minimum operating
requirements in the pro forma LGIA and pro forma SGIA, including
maximum droop and deadband parameters and provisions for timely and
sustained response.
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\1\ 16 U.S.C. 824e.
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2. These requirements apply to newly interconnecting generation
facilities that execute, or request the unexecuted filing of, an LGIA
or SGIA on or after the effective date of this final action. These
requirements also apply to existing large and small generating
facilities that take any action that requires the submission of a new
interconnection request that results in the filing of an executed or
unexecuted interconnection agreement on or after the effective date of
this final action. These requirements do not apply to existing
generating facilities,\2\ a subset of combined heat and power (CHP)
facilities, or generating facilities regulated by the Nuclear
Regulatory Commission (NRC). In addition, the Commission does not
impose a headroom requirement for new generating facilities, and does
not mandate that new generating facilities receive compensation for
complying with the primary frequency response requirements.
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\2\ As discussed below in Section II.G, we will not impose
primary frequency response requirements on existing generating
facilities that do not submit new interconnection requests that
result in an executed or unexecuted interconnection agreement at
this time.
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3. The modifications address the Commission's concerns that the
existing pro forma LGIA contains limited primary frequency response
requirements that apply only to synchronous generating facilities and
do not account for recent technological advancements that now enable
new non-synchronous generating facilities to have primary frequency
response capabilities. Further, the Commission believes that it is
unduly discriminatory or preferential to impose primary frequency
response requirements only on new large generating facilities but not
on new small generating facilities. The reforms adopted here impose
comparable primary frequency response requirements on both new large
and small generating facilities.
I. Background
A. Frequency Response
4. Reliable operation of an Interconnection \3\ depends on
maintaining frequency within predetermined boundaries above and below a
scheduled value, which is 60 Hertz (Hz) in North America. Changes in
frequency are caused by changes in the balance between load and
generation, such as the sudden loss of a large generator or a large
amount of load. If frequency deviates too far above or below its
scheduled value, it could potentially result in under frequency load
shedding (UFLS), generation tripping, or cascading outages.\4\
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\3\ An Interconnection is a geographic area in which the
operation of the electric system is synchronized. In the continental
United States, there are three Interconnections, namely, the
Eastern, Texas, and Western Interconnections.
\4\ UFLS is designed to be activated in extreme conditions to
stabilize the balance between generation and load. Under frequency
protection schemes are drastic measures employed if system frequency
falls below a specified value. See Automatic Underfrequency Load
Shedding and Load Shedding Plans Reliability Standards, Notice of
Proposed Rulemaking, 76 FR 66220 (Oct. 26, 2011), FERC Stats. &
Regs. ] 32,682, at PP 4-10 (2011).
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5. Mitigation of frequency deviations after the sudden loss of
generation or load is driven by three primary factors: inertial
response, primary frequency response, and secondary frequency
response.\5\ Primary frequency response actions begin within seconds
after system frequency changes and are mostly provided by the automatic
and autonomous actions (i.e., outside of system operator control) of
turbine-governors, while some response is provided by frequency
responsive loads.\6\ Primary frequency response actions are intended to
arrest abnormal frequency deviations and ensure that
[[Page 9638]]
system frequency remains within acceptable bounds. An important goal
for system planners and operators is for the frequency nadir,\7\ during
large disturbances, to remain above the first stage of UFLS set points
within an Interconnection.
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\5\ In the Notice of Inquiry issued in Docket No. RM16-6-000 on
February 8, 2016, the Commission provided detailed discussion of how
inertia, primary frequency response, and secondary frequency
response interact to mitigate frequency deviations. Essential
Reliability Services and the Evolving Bulk-Power System--Primary
Frequency Response, 154 FERC ] 61,117, at PP 3-7 (2016) (NOI). See
also Use of Frequency Response Metrics to Assess the Planning and
Operating Requirements for Reliable Integration of Variable
Renewable Generation, Lawrence Berkeley National Laboratory, at 13-
14 (Dec. 2010), http://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf
(LBNL 2010 Report).
\6\ NOI, 154 FERC ] 61,117 at P 6. The Commission also noted
that regulation service is different than primary frequency response
because generating facilities that provide regulation respond to
automatic generation control signals and regulation service is
centrally coordinated by the system operator, whereas primary
frequency response service, in contrast, is autonomous and is not
centrally coordinated. Schedule 3 of the pro forma Open Access
Transmission Tariff (OATT) bundles these different services
together. See id. n.66.
\7\ The point at which the frequency decline is arrested
(following the sudden loss of generation) is called the frequency
nadir, and represents the point at which the net primary frequency
response (real power) output from all generating units and the
decrease in power consumed by the load within an Interconnection
matches the net initial loss of generation (in megawatts (MW)).
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6. Frequency response is a measure of an Interconnection's ability
to arrest and stabilize frequency deviations following the sudden loss
of generation or load, and is affected by the collective responses of
generation and load throughout the Interconnection. When considered in
aggregate, the primary frequency response provided by generators within
an Interconnection has a significant impact on the overall frequency
response. Reliability Standard BAL-003-1.1 defines the amount of
frequency response needed from balancing authorities \8\ to maintain
Interconnection frequency within predefined bounds and includes
requirements for the measurement and provision of frequency
response.\9\ While Reliability Standard BAL-003-1.1 establishes
requirements for balancing authorities, it does not include any
requirements applicable to individual generator owners or
operators.\10\
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\8\ NERC's Glossary of Terms defines a balancing authority as
``(t)he responsible entity that integrates resource plans ahead of
time, maintains load-interchange-generation balance within a
balancing authority area, and supports Interconnection frequency in
real time.'' NERC's Glossary of Terms is available at: http://www.nerc.com/files/glossary_of_terms.pdf.
\9\ Frequency Response and Frequency Bias Setting Reliability
Standard, Order No. 794, 146 FERC ] 61,024 (2014).
\10\ The Commission has also accepted Regional Reliability
Standard BAL-001-TRE-01 (Primary Frequency Response in the ERCOT
Region) as mandatory and enforceable, which does establish
requirements for generator owners and operators with respect to
governor control settings and the provision of primary frequency
response within the Electric Reliability Council of Texas (ERCOT)
region. North American Electric Reliability Corporation, 146 FERC ]
61,025 (2014).
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7. Unless otherwise required by tariffs or interconnection
agreements, generator owners and operators can independently decide
whether to configure their generating facilities to provide primary
frequency response.\11\ The magnitude and duration of a generating
facility's response to frequency deviations is generally determined by
the settings of the facility's governor \12\ (or equivalent controls)
and other plant-level (e.g., ``outer-loop'') control systems.\13\ In
particular, the governor's droop and deadband settings have a
significant impact on the unit's provision of primary frequency
response. In addition, plant-level controls, unless properly
configured, can override or nullify a generator's governor response and
return the unit to operate at a scheduled pre-disturbance megawatt set-
point.\14\ In 2010, NERC conducted a survey of generator owners and
operators and found that only approximately 30 percent of generating
facilities in the Eastern Interconnection provided primary frequency
response, and that only approximately 10 percent of generating
facilities provided sustained primary frequency response.\15\ This
suggests that many generating facilities within the Eastern
Interconnection disable or otherwise set their governors or plant-level
controls such that they provide little to no primary frequency
response.\16\
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\11\ See NOI, 154 FERC ] 61,117 at PP 18-19.
\12\ A governor is an electronic or mechanical device that
implements primary frequency response on a generating facility via a
droop parameter. Droop refers to the variation in real power (MW)
output due to variations in system frequency and is typically
expressed as a percentage (e.g., 5 percent droop). Droop reflects
the amount of frequency change from nominal (e.g., 5 percent of 60
Hz is 3 Hz) that is necessary to cause the main prime mover control
mechanism of a generating facility to move from fully closed to
fully open. A governor also has a deadband parameter which
represents a minimum frequency deviation (e.g., 0.036
Hz) from nominal system frequency (i.e., 60 Hz in North America)
that must be exceeded in order for the generating facility to
provide primary frequency response.
\13\ These controls are known as plant-level or outer-loop
controls to distinguish them from more direct, lower-level control
of the generator operations.
\14\ For more discussion on ``premature withdrawal'' of primary
frequency response, see NOI, 154 FERC ] 61,117 at PP 49-50.
\15\ See NERC, Frequency Response Initiative Report: The
Reliability Role of Frequency Response (Oct. 2012), http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf
(NERC Frequency Response Initiative Report) at 95. For the purposes
of this final action, as indicated below in the revised pro forma
language in Section K, sustained response refers to a generating
facility responding to an abnormal frequency deviation outside of
the deadband parameter, and holding (i.e., not prematurely
withdrawing) the response until system frequency returns to a value
that is within the deadband.
\16\ However, as noted below, some commenters note that nuclear
generating facilities are restricted by their NRC operating licenses
regarding the provision of primary frequency response.
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8. Declining frequency response performance has been an industry
concern for many years. NERC, in conjunction with the Electric Power
Research Institute (EPRI), initiated its first examination of declining
frequency response and governor response in 1991.\17\ More recently, as
noted in the NOI, while the three U.S. Interconnections currently
exhibit adequate frequency response performance above their
Interconnection Frequency Response Obligations,\18\ there has been a
decline in the frequency response performance of the Western and
Eastern Interconnections from historic values.\19\
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\17\ NERC Frequency Response Initiative Report at 22.
\18\ The Interconnection Frequency Response Obligations are
established by NERC and are designed to require sufficient frequency
response for each Interconnection (i.e., the Eastern, ERCOT, Quebec,
and Western Interconnections) to arrest frequency declines even for
severe, but possible, contingencies.
\19\ NOI, 154 FERC ] 61,117 at P 20.
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B. Prior Commission Actions
9. In Order Nos. 2003 \20\ and 2006,\21\ the Commission adopted
standard procedures for the interconnection of large and small
generating facilities, including the development of standardized pro
forma generator interconnection agreements and procedures. The
Commission required public utility transmission providers \22\ to file
revised OATTs containing these standardized provisions, and use the
LGIA and SGIA to provide non-discriminatory interconnection service to
Large Generators (i.e., generating facilities having a capacity of more
than 20 MW) and Small Generators (i.e., generators having a capacity of
no more than 20 MW). The pro forma LGIA and pro forma SGIA have since
been revised through various subsequent proceedings.\23\
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\20\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
\21\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ]
31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs. ]
31,196 (2005), order granting clarification, Order No. 2006-B, FERC
Stats. & Regs. ] 31,221 (2006).
\22\ A public utility is a utility that owns, controls, or
operates facilities used for transmitting electric energy in
interstate commerce, as defined by the FPA. See 16 U.S.C. 824(e)
(2012). A non-public utility that seeks voluntary compliance with
the reciprocity condition of an OATT may satisfy that condition by
filing an OATT, which includes a LGIA and SGIA. See Order No. 2003,
FERC Stats. & Regs. ] 31,146 at PP 840-845.
\23\ E.g., Small Generator Interconnection Agreements and
Procedures, Order No. 792, 145 FERC ] 61,159 (2013), clarifying,
Order No. 792-A, 146 FERC ] 61,214 (2014); Reactive Power
Requirements for Non-Synchronous Generation, Order No. 827, FERC
Stats. & Regs. ] 31,385 (2016) (cross-referenced at 155 FERC ]
61,277) (2016); Requirements for Frequency and Voltage Ride Through
Capability of Small Generating Facilities, Order No. 828, 156 FERC ]
61,062 (2016).
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C. Notice of Inquiry
10. On February 18, 2016, the Commission issued the NOI to explore
issues regarding essential reliability services and the evolving Bulk-
Power System.\24\ In particular, the Commission asked a broad range of
questions on the need for reform of its requirements regarding the
provision of and compensation for primary frequency response. The
Commission explained that there is a significant risk that, as
conventional synchronous generating facilities retire or are displaced
by increased numbers of variable energy resources (VERs),\25\ which
typically do not contribute to system inertia \26\ or have primary
frequency response capabilities, the net amount of frequency responsive
generation online will be reduced.\27\
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\24\ NOI, 81 FR 9182 (Feb. 24, 2016), 154 FERC ] 61,117.
\25\ The term VER is defined as a device for the production of
electricity that is characterized by an energy source that: (1) Is
renewable; (2) cannot be stored by the facility owner or operator;
and (3) has variability that is beyond the control of the facility
owner or operator. See, e.g., Integration of Variable Energy
Resources, Order No. 764, FERC Stats. & Regs. ] 31,331 at P 210,
order on reh'g and clarification, Order No. 764-A, 141 FERC ] 61,232
(2012), order on clarification and reh'g, Order No. 764-B, 144 FERC
] 61,222 (2013).
\26\ Inertial response, or system inertia, involves the release
or absorption of kinetic energy by the rotating masses of online
generation and load within an Interconnection, and is the result of
the coupling between the rotating masses of synchronous generation
and load and the electric system. See NOI, 154 FERC ] 61,117 at PP
3-7 for a more detailed discussion of how inertia, primary frequency
response, and secondary frequency response interact to mitigate
frequency deviations.
\27\ NOI, 154 FERC ] 61,117 at P 12.
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11. In the NOI, the Commission also explained that these
developments and their potential impacts could challenge system
operators in maintaining system frequency within acceptable bounds
following system disturbances.\28\ Further, the Commission explained
that Reliability Standard BAL-003-1.1 and the pro forma LGIA and pro
forma SGIA do not specifically address a generator's ability to provide
frequency response.\29\ The Commission noted, however, that while in
previous years many non-synchronous generating facilities \30\ were not
designed with primary frequency response capabilities, the technology
now exists for new non-synchronous generating facilities to install
primary frequency response capability.\31\
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\28\ Id. P 14.
\29\ Id. P 41.
\30\ Non-synchronous generating facilities are ``connected to
the bulk power system through power electronics, but do not produce
power at system frequency (60 Hz).'' They ``do not operate in the
same way as traditional generators and respond differently to
network disturbances.'' PJM Interconnection, L.L.C., 151 FERC ]
61,097, at P 1 n.3 (2015) (citing Interconnection for Wind Energy,
Order No. 661, FERC Stats. & Regs. ] 31,198, at P 3 n.4 (2005)).
Wind and solar photovoltaic generating facilities as well as
electric storage resources are examples of non-synchronous
generating facilities.
\31\ NOI, 154 FERC ] 61,117 at P 43.
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12. Accordingly, the Commission requested comments on three main
sets of issues. First, the Commission sought comment on whether
amendments to the pro forma LGIA and pro forma SGIA are warranted to
require all new generating facilities, both synchronous and non-
synchronous, to have primary frequency response capabilities as a
precondition of interconnection.\32\ Second, the Commission sought
comment on the performance of existing generating facilities and
whether primary frequency response requirements for these facilities
are warranted.\33\ Finally, the Commission sought comment on
compensation for primary frequency response.\34\
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\32\ Id. PP 2 and 44-45.
\33\ Id. PP 2, 46, and 52.
\34\ Id. PP 2, 53-54.
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D. Notice of Proposed Rulemaking
13. On November 17, 2016, the Commission issued a Notice of
Proposed Rulemaking that proposed to revise the pro forma LGIA and the
pro forma SGIA to require all newly interconnecting large and small
generating facilities, both synchronous and non-synchronous, to install
and enable primary frequency response capability as a condition of
interconnection.\35\ The Commission also proposed to establish certain
operating requirements in the pro forma LGIA and pro forma SGIA,
including maximum droop and deadband parameters, and provisions for
timely and sustained response.
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\35\ Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response, Notice of Proposed Rulemaking,
81 FR 85176 (Nov. 25, 2016), 157 FERC ] 61,122 (2016) (NOPR).
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14. The Commission sought comment on the proposed: (1) Requirements
for new large and small generating facilities to install, maintain, and
operate a governor or equivalent controls; (2) requirements for droop
and deadband settings of 5 percent and 0.036 Hz,
respectively; (3) requirements for timely and sustained response, and
in particular whether the proposed requirements will be sufficient to
prevent plant-level controls from inhibiting primary frequency
response; (4) requirement for droop parameters to be based on nameplate
capability with a linear operating range of 59 to 61 Hz; and (5)
exemptions for new nuclear units. The Commission also sought comment on
its proposal to not impose a generic headroom requirement or mandate
compensation related to the proposed reforms.
15. Twenty-eight entities submitted comments in response to the
NOPR and are listed in Appendix A to this final action.
E. Notice of Request for Supplemental Comments
16. On August 18, 2017, the Commission issued a Notice of Request
for Supplemental Comments (Supplemental Notice) to augment the record
on the potential impacts of the NOPR proposals on electric storage
resources \36\ and small generating facilities.\37\ In particular, the
Commission stated that the NOPR did not contain any special
consideration or provisions for electric storage resources, and that
some commenters raised concerns that, by failing to address electric
storage resources' unique technical attributes, the proposed
requirements could pose an unduly discriminatory burden on electric
storage resources.\38\ In response to commenters' concerns, the
Commission asked several questions to augment the record on possible
impacts to electric storage facilities.\39\
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\36\ For the purposes of this final action, we define an
electric storage resource as a resource capable of receiving
electric energy from the grid and storing it for later injection of
electric energy back to the grid. This definition is also used in a
concurrently-issued Final Rule, published elsewhere in this issue of
the Federal Register, concerning electric storage resources entitled
Electric Storage Participation in Markets Operated by Regional
Transmission Organizations and Independent System Operators, 162
FERC ] 61,127 (2018).
\37\ Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response, Notice of Request for
Supplemental Comments, 82 FR 40081 (Aug. 24, 2017), 160 FERC ]
61,011 (2017).
\38\ Id. P 4.
\39\ Id. P 6.
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17. In addition, the Commission stated that the NOPR proposed that
small generating facilities be subject to new primary frequency
response requirements in the pro forma SGIA, and that some commenters
raised concerns that small generating facilities could face
disproportionate costs to install primary frequency response
capability,\40\ while other commenters requested that the Commission
consider adopting a size limitation.\41\ In response to commenters'
concerns, the Commission asked several questions to augment the record
on small generating facilities.\42\
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\40\ Id. P 8.
\41\ Id. P 9.
\42\ Id. P 10.
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18. Twenty entities submitted comments in response to the notice of
[[Page 9640]]
request for supplemental comments and are listed in Appendix B to this
final action.
II. Discussion
19. For the reasons discussed below, the Commission adopts the NOPR
proposal and will require newly interconnecting large and small
generating facilities that interconnect pursuant to the pro forma LGIA
or pro forma SGIA, to install, maintain, and operate a functioning
governor or equivalent controls capable of providing primary frequency
response. The reforms adopted here build upon Order Nos. 2003 and 2006
by accounting for the effect upon primary frequency response from the
ongoing changes to the nation's generation resource mix, including
significant retirements of conventional generating facilities and an
increasing proportion of VERs interconnecting to the Bulk-Power
System.\43\ Another important consideration is that the frequency
response performance of the Eastern and Western Interconnections, while
currently adequate, has significantly declined from historic
values.\44\ NERC has found that ``increasing levels of non-synchronous
resources installed without controls that enable frequency response
capability, coupled with retirement of conventional generating
facilities that have traditionally provided primary frequency response,
have contributed to the decline in primary frequency response.'' \45\
Finally, the record in this proceeding indicates that VER equipment
manufacturers have made significant technological advancements in
developing primary frequency response capability for VERs, and that the
costs of this capability have declined over time.\46\ For all of these
reasons, we find that the pro forma LGIA and pro forma SGIA are no
longer just and reasonable, and are unduly discriminatory or
preferential, and thus need to be revised to ensure that all newly
interconnecting large and small generating facilities have primary
frequency response capability as a condition of interconnection.\47\
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\43\ Section 215(a)(1) of the FPA, 16 U.S.C. 824o(a)(1) (2012)
defines ``Bulk-Power System'' as those ``facilities and control
systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof) [and] electric energy
from generating facilities needed to maintain transmission system
reliability.'' The term does not include facilities used in the
local distribution of electric energy. See also Mandatory
Reliability Standards for the Bulk-Power System, Order No. 693, FERC
Stats. & Regs. ] 31,242, at P 76 (cross-referenced at 118 FERC ]
61,218), order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007).
\44\ See NOPR, 157 FERC ] 61,122 at P 36 (citing NERC Frequency
Response Initiative Industry Advisory--Generator Governor Frequency
Response, at slide 10 (Apr. 2015), http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. See
also NERC Frequency Response Initiative Report at 22, and LBNL 2010
Report at xiv-xv).
\45\ NERC Comments at 5. NERC's Essential Reliability Services
Task Force has determined that primary frequency response is an
``essential reliability service.'' Essential reliability services
are referred to as elemental reliability building blocks from
resources (generation and load) that are necessary to maintain the
reliability of the Bulk-Power System. See Essential Reliability
Services Task Force Scope Document, at 1 (Apr. 2014), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
\46\ NOPR, 157 FERC ] 61,122 at PP 28, 36.
\47\ 16 U.S.C. 824e. The Commission routinely evaluates the
effectiveness of its regulations and policies in light of changing
industry conditions to determine if changes in these conditions and
policies are necessary. See, e.g., Order No. 764, FERC Stats. &
Regs. ] 31,331.
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20. We find that the current requirements for governor controls in
the pro forma LGIA do not reflect NERC's currently recommended
operating practices or recent advances in technology for non-
synchronous generating facilities, as discussed below.
21. First, Article 9.6.2.1 of the pro forma LGIA does not address
the settings of governors or equivalent controls (i.e., deadband and
droop), nor does Article 9.6.2.1 address plant-level controls, which if
not properly coordinated on a generating facility, can lead to the
premature withdrawal of primary frequency response during disturbances.
Furthermore, the substantial body of knowledge regarding the operation
of generator governors and plant control systems amassed by NERC and
industry stakeholders since the pro forma LGIA was promulgated under
Order No. 2003 raises concerns that Article 9.6.2.1 of the pro forma
LGIA allows too much discretion for generator owners and operators. For
example, in 2012, NERC found that a number of generators implemented
deadband settings that were so wide as to effectively disable
themselves from providing primary frequency response, and also that
many generators provide frequency response in the wrong direction
during a disturbance.\48\ In addition, in 2015, NERC observed that: (1)
For many conventional steam plants, deadband settings exceeded 0.036 Hz; (2) several generating facilities failed to sustain
primary frequency response; and (3) the vast majority of the gas
turbine fleet was not frequency responsive.\49\
---------------------------------------------------------------------------
\48\ NERC Frequency Response Initiative Report at 92, 96-97.
\49\ NOI, 154 FERC ] 61,117 at P 50 (citing NERC Generator
Governor Frequency Response Advisory--Webinar Questions and Answers
at 1 (April 2015), http://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_QandA_April_2015.pdf.).
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22. Second, existing Article 9.6.2.1 of the pro forma LGIA states
that ``speed governors,'' if installed, must be operated in automatic
mode. However, instead of utilizing traditional speed governors to
implement primary frequency response capability, many new non-
synchronous generating facilities interconnecting to the grid, such as
wind, solar, and electric storage resources, utilize enhanced inverters
and other plant control technology that can be designed to include
primary frequency response capability.\50\ We find that due to these
recent technological advancements that allow new large non-synchronous
generating facilities to install primary frequency response capability
at low cost, as well as the expected overall increase of the proportion
of the resource mix that are non-synchronous generating facilities, it
is unduly discriminatory and preferential to only require synchronous
generators to provide primary frequency response. The references to
``speed governors'' in existing Article 9.6.2.1 of the pro forma LGIA,
which are only applicable to large synchronous generating facilities,
are outdated and should be expanded to include both synchronous and
non-synchronous generators.
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\50\ See Electric Power Research Institute, Recommended Settings
for Voltage and Frequency Ride-Through of Distributed Energy
Resources at 27(May 2015), http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002006203. See also National
Renewable Energy Labs (NREL), Advanced Grid-Friendly Controls
Demonstration Project for Utility-Scale PV Power Plants, at 1-2
(Jan. 2016), http://www.nrel.gov/docs/fy16osti/65368.pdf.
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23. Investigation by various NERC task forces and subcommittees has
led to a voluntary NERC Primary Frequency Control Guideline that
includes recommended droop and deadband settings for generating
facilities within all three U.S. Interconnections.\51\ However, as
noted in the NOPR, the pro forma LGIA and pro forma SGIA do not
currently reflect these updated recommended practices by NERC for
governor and plant control system settings of generating
facilities.\52\
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\51\ See NERC's Primary Frequency Control Guideline.
\52\ NOPR, 157 FERC ] 61,122 at P 39.
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24. We also find that revisions to the pro forma LGIA and pro forma
SGIA are necessary to provide for the continued reliable operation of
the Bulk-Power System by addressing the potential adverse impacts on
primary frequency response of the nation's evolving generation resource
mix described in the NOI.\53\ As noted in the NOPR,
[[Page 9641]]
NERC's Essential Reliability Services Task Force concluded that primary
frequency response capability should be required of all new generating
facilities.\54\ However, the pro forma LGIA and the pro forma SGIA do
not currently require generating facilities to install such capability.
---------------------------------------------------------------------------
\53\ NOI, 154 FERC ] 61,117 at PP 13-17 (citing to the Essential
Reliability Services Task Force Measures Report at iv).
\54\ NOPR, 157 FERC ] 61,122 at P 15.
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25. Further, the limited references to primary frequency response
in the Commission's requirements apply only to large generating
facilities. Based on the absence of a technical or economic basis for
the different requirements imposed on small and large generating
facilities, and the significant technological advancements that
manufacturers have made in developing primary frequency response
capability for VERs, we find that the absence of any similar provisions
in the current pro forma SGIA is unduly discriminatory or preferential.
26. The Commission has previously acted under FPA section 206 to
remove inconsistencies between the pro forma LGIA and pro forma SGIA
when there is no economic or technical basis for treating large and
small generating facilities differently.\55\ As discussed more fully
below in Section II.H.7, the record developed in this proceeding
indicates that small generating facilities are capable of installing
and enabling governors or equivalent controls at a low cost and in a
manner comparable to large generating facilities.\56\ Given these low-
cost technological advances, we do not anticipate that these additional
requirements added to the pro forma SGIA will present a barrier to
entry for small generating facilities. Thus, in light of the need for
additional primary frequency response capability and an increasingly
large market penetration of small generating facilities, we believe
that there is a need to add these requirements to the pro forma SGIA to
help ensure adequate primary frequency response capability.
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\55\ See Order No. 828, 156 FERC ] 61,062 (revising the pro
forma SGIA such that small generating facilities have frequency and
voltage ride through requirements comparable to large generating
facilities).
\56\ See, e.g., IEEE-P1547 Working Group NOI Comments at 1, 5,
and 7; ISO-RTO Council Supplemental Comments at 7; SoCal Edison
Supplemental Comments at 3; WIRAB Supplemental Comments at 7.
Moreover, the Commission notes that other commenters stated costs of
installing primary frequency response capability are generally low,
but did not differentiate between small and large generating
facilities. See, e.g., APPA, et al. Comments at 6; California Cities
Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at
3-5; SoCal Edison Comments at 2.
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27. Accordingly, we find that revising the pro forma LGIA and pro
forma SGIA to require all new generating facilities to install,
maintain, and operate a functioning governor or equivalent controls,
consistent with the exceptions and operating requirements described
below, is just and reasonable. Doing so will help to ensure adequate
primary frequency response capability as the generation resource mix
continues to evolve, ensure fair and consistent treatment for all types
of generating facilities, help balancing authorities meet their
frequency response obligations pursuant to Reliability Standard BAL-
003-1.1, and help improve reliability, particularly during system
restoration and islanding situations.\57\
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\57\ NOPR, 157 FERC ] 61,122 at P 43.
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A. Requirement To Install, Maintain, and Operate Equipment Capable of
Providing Primary Frequency Response
1. NOPR Proposal
28. In the NOPR, the Commission proposed to revise the pro forma
LGIA and pro forma SGIA to include requirements for new large and small
generating facilities, both synchronous and non-synchronous, to
install, maintain, and operate equipment capable of providing primary
frequency response as a condition of interconnection.\58\ In
particular, the Commission explained that the proposed revisions would
require new large and small generating facilities to install, maintain,
and operate a functioning governor or equivalent controls, which the
Commission proposed to define as the required hardware and/or software
that provides frequency responsive real power control with the ability
to sense changes in system frequency and autonomously adjust the
generating facility's real power output in accordance with the proposed
maximum droop and deadband parameters and in the direction needed to
correct frequency deviations.\59\
---------------------------------------------------------------------------
\58\ Id. P 44.
\59\ Id. P 47.
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2. Comments
29. The proposed requirement for new generating facilities to
install the necessary equipment for primary frequency response
capability as a condition of interconnection received broad support
from commenters.\60\ For example, APPA et al. state that requiring
newly interconnecting generating facilities to install governors or
equivalent control devices is a relatively low-cost way to prevent the
erosion of the Interconnections' collective frequency response
capability as the generation resource mix evolves.\61\ APPA et al.
state that primary frequency response capability should be a standard
feature and part of the ``rules of the road'' for all new generating
facilities, similar to how all new cars come equipped with anti-lock
brakes.\62\ Bonneville asserts that the trend of declining frequency
response capability will continue with a changing generation resource
mix (namely, the integration of large amounts of VERs), unless
provisions are put in place to ensure that adequate primary frequency
response capability is available in the future.\63\ As a result,
Bonneville believes that it is necessary to require newly
interconnecting generating facilities to have primary frequency
response capability.\64\ EEI states that now that the technology is
available and economical for non-synchronous generation facilities, it
supports the proposed requirement for these facilities to install the
equipment needed to provide primary frequency response.\65\
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\60\ APPA et al., Bonneville, California Cities, EEI, ESA,
Competitive Suppliers, First Solar, Idaho Power (for generating
facilities larger than 10 MW), ISO-RTO Council, MISO TOs, NERC,
PG&E, SoCal Edison, SVP, Tri-State, Xcel, and WIRAB support the
requirement for new generating facilities to install governors or
equivalent controls. In addition, AWEA states that it does not
oppose a primary frequency response capability requirement.
\61\ APPA et al. Comments at 6.
\62\ Id.
\63\ Bonneville Comments at 2.
\64\ Id.
\65\ EEI Comments at 2.
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30. NERC states that it has determined that increasing levels of
non-synchronous generating facilities installed without controls that
enable frequency response capability, coupled with retirement of
conventional generating facilities that have traditionally provided
primary frequency response, has contributed to the decline in primary
frequency response.\66\ NERC further states that a changing generation
resource mix will further alter the dispatch of generating facilities,
potentially resulting in operating conditions where frequency response
capability could be diminished unless a sufficient amount of frequency
responsive capacity is included in the dispatch.\67\ NERC asserts that
the NOPR's proposed revisions would apply measurable, clear
requirements to newly interconnecting synchronous and non-synchronous
generating facilities.\68\ Tri-State comments that primary frequency
response requirements for all generating facilities are necessary to
address the
[[Page 9642]]
decline in frequency response and are in the best interest of
industry.\69\ ISO-RTO Council adds that a number of Regional
Transmission Operators (RTOs) and Independent System Operators (ISOs)
have, for several years, had similar requirements to those proposed in
the NOPR, and as a result, the Commission's proposal does not create
significant burdens as it merely extends these existing ``best
practices'' nationwide.\70\ SVP states that the NOPR proposals should
not create a major hardship in terms of costs or other burdens related
to installing frequency response capability.\71\ SoCal Edison states
that there is neither a technological nor an economic reason not to
require primary frequency response capability of small and/or non-
synchronous generating facilities.\72\
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\66\ NERC Comments at 5.
\67\ Id.
\68\ Id.
\69\ Tri-State Supplemental Comments at 3.
\70\ ISO-RTO Council Comments at 2.
\71\ SVP Comments at 2.
\72\ SoCal Edison Comments at 2.
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31. On the other hand, some commenters do not support a requirement
for new generating facilities to install, maintain, and operate primary
frequency response capability as a condition of interconnection.\73\
For example, API states that primary frequency response operation may
not be required from all generating facilities since it is possible for
balancing authorities to have a sufficient number of existing
generating facilities with primary frequency response capability.\74\
APS argues that more time is needed to measure and understand the
effect of Reliability Standard BAL-003-1.1 on frequency response before
mandating primary frequency response capability.\75\ Chelan County adds
that while it may be true that it is more cost effective to install
primary frequency response capability during a generating facility's
initial construction (as opposed to retrofitting an already-existing
generating facility) and the costs of doing so may be nominal, the
Commission should not require generating facilities to provide primary
frequency response as a condition of interconnection.\76\ NRECA asserts
that the proposal could have adverse impacts on deployment of non-
traditional generation sources without conferring reliability benefits
that warrant such risks.\77\ Therefore, NRECA asserts that if the
Commission proceeds to require primary frequency response capability as
a condition of interconnection, then the Commission should provide for
flexibility to balance the reliability needs with possible costs and
the desire to encourage new generating facilities by: (1) Considering a
size threshold, whereby new generators under a certain size are not
required to have primary frequency response capability; (2)
establishing penetration level thresholds for primary frequency
response requirements; or (3) allowing for a waiver process.\78\
---------------------------------------------------------------------------
\73\ See, e.g., API Comments at 2; APS Supplemental Comments at
12; Chelan County Comments at 1; NRECA Comments at 2; Public
Interest Organizations Comments at 4; R Street Comments at 2; SDG&E
Comments at 1; Sunflower and Mid-Kansas Comments at 2.
\74\ API Comments at 4.
\75\ APS Supplemental Comments at 12.
\76\ Chelan County Comments at 1.
\77\ NRECA Comments at 6.
\78\ Id. at 8-9.
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32. In addition, some of these commenters request that the
Commission reconsider its proposal to mandate the installation of
specific equipment on all new generating facilities (or the operation
of such equipment as proposed in the NOPR) as a condition of
interconnection, and to instead direct market-based or cost-based
approaches to ensure adequate levels of primary frequency response.\79\
---------------------------------------------------------------------------
\79\ See, e.g., API Comments at 2; Chelan County Comments at 1;
Public Interest Organizations Comments at 4; R Street Comments at 2-
3; SDG&E Comments at 1, 3-4.
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3. Commission Determination
33. We adopt the NOPR proposal to revise the pro forma LGIA and pro
forma SGIA to include requirements for new large and small generating
facilities, both synchronous and non-synchronous, to install, maintain,
and operate equipment capable of providing primary frequency response
as a condition of interconnection, with certain exemptions and special
accommodations as discussed below in Section II.H.
34. We adopt the NOPR proposal to define ``functioning governor or
equivalent controls'' as the required hardware and/or software that
provides frequency responsive real power control with the ability to
sense changes in system frequency and autonomously adjust the
generating facility's real power output in accordance with maximum
droop and deadband parameters and in the direction needed to correct
frequency deviations.\80\
---------------------------------------------------------------------------
\80\ NOPR, 157 FERC ] 61,122 at P 47.
---------------------------------------------------------------------------
35. The proposal to require new generating facilities to install
equipment capable of providing primary frequency response received
broad support from commenters.\81\ We find compelling these commenters'
observations that requiring newly interconnecting generating facilities
to install governors or equivalent control devices is a low cost way to
address the erosion of the Interconnections' collective frequency
response capability as the generation resource mix evolves. As
assessments by NERC, the Essential Reliability Services Task Force, and
others confirm, ongoing changes to the generation resource mix are
altering the composition and dispatch of generating facilities across
the daily and seasonal demand spectrum. The resulting operating
conditions have affected frequency response capability and the amount
of frequency responsive capacity online at any given moment. We believe
that the revisions to the pro forma LGIA and pro forma SGIA adopted
here will address this problem by providing that the future generation
resource mix has frequency responsive capacity available for dispatch
by system operators to maintain system reliability.
---------------------------------------------------------------------------
\81\ APPA et al., Bonneville, California Cities, EEI, ESA,
Competitive Suppliers, First Solar, Idaho Power (for generating
facilities larger than 10 MW), ISO-RTO Council, MISO TOs, NERC,
PG&E, SoCal Edison, SVP, Tri-State, Xcel, and WIRAB support the
requirement for new generating facilities to install governors or
equivalent controls.
---------------------------------------------------------------------------
36. We acknowledge that some commenters do not support a
requirement for all newly interconnecting generating facilities to
install, maintain, and operate governors or equivalent controls.\82\
Some of these commenters only support a requirement for newly
interconnecting generating facilities to install primary frequency
response capability as a condition of interconnection, but do not
support including the proposed operating requirements in the pro forma
LGIA and pro forma SGIA.\83\ These commenters either advocate for
regional flexibility (i.e., allowing the transmission provider or the
balancing authority to establish regional requirements) or request
exemption or special accommodation of the requirements for particular
technology types (e.g., electric storage resources and CHP facilities).
Comments that request regional flexibility for individual transmission
providers or balancing authorities to establish operating requirements
are addressed below in Section II.B. Comments that request a special
accommodation for certain types of generating facilities, including but
not limited to electric storage and CHP facilities are addressed below
in Section II.H.
---------------------------------------------------------------------------
\82\ See, e.g., API Comments at 2; APS Supplemental Comments at
12; Chelan County Comments at 1; NRECA Comments at 2; Public
Interest Organizations Comments at 4; R Street Comments at 2; SDG&E
Comments at 1; Sunflower and Mid-Kansas Comments at 2.
\83\ See, e.g., AES Companies Comments at 6; EEI Comments at 8;
MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel
Comments at 7.
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[[Page 9643]]
37. Rather than uniform requirements in the pro forma LGIA and pro
forma SGIA, some commenters prefer market-based or cost-based
compensation mechanisms to ensure sufficient primary frequency response
capability, and urge the Commission to consider the economic impacts of
the proposed requirements on load. Comments related to compensation are
addressed below in Section II.E. Comments related to the impacts on
load are addressed below in Section II.H.8.
38. Finally, some commenters assert that the Commission should: (1)
Consider a size threshold; (2) establish penetration level thresholds
for primary frequency response requirements; (3) allow for a waiver
process; and (4) establish primary frequency response pools. These
comments are addressed below in Sections II.H and II.J.
39. Accordingly, as a result of this final action, new large and
small generating facilities, will be required to install, maintain, and
operate a functioning governor or equivalent controls with certain
exemptions or accommodations for nuclear generating facilities,
electric storage facilities, and combined heat and power facilities as
discussed below.
B. Including Operating Requirements for Droop and Deadband in the Pro
Forma LGIA and Pro Forma SGIA
1. NOPR Proposal
40. In the NOPR, the Commission proposed to include minimum
operating requirements for droop and deadband for governors or
equivalent controls.\84\ In particular, the Commission proposed to
require new generating facilities to install, maintain, and operate
governor or equivalent controls with the ability to operate with a
maximum 5 percent droop and 0.036 Hz deadband parameter,
consistent with NERC's recommended guidance.\85\
---------------------------------------------------------------------------
\84\ NOPR, 157 FERC ] 61,122 at P 48.
\85\ Id.
---------------------------------------------------------------------------
41. The Commission also proposed to require the droop parameter to
be based on the nameplate capability of the generating facility and
linear in operating range between 59 and 61 Hz.\86\ The Commission
explained that this provision is reasonable because it would allow for
new generating facilities that remain connected during frequency
deviations (and have operating capability, e.g., headroom; \87\ or
floor-room \88\ at the time of the disturbance) to provide a
proportional response within this range of frequencies.\89\
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\86\ Id. P 50.
\87\ For the purposes of this final action, headroom refers to
the difference between the current operating point of a generating
facility and its maximum operating capability, and represents the
potential amount of additional energy that can be provided by the
generating facility in real-time. See NOPR, 157 FERC ] 61,122 at
n.27.
\88\ For the purposes of this final action, floor-room refers to
the difference between the current operating point of a generating
facility and its minimum operating capability, and represents the
potential amount of additional energy that can be withdrawn by the
generating facility in real-time. Stated differently, a generating
facility with floor-room will have the capability to reduce its MW
output in response to a frequency deviation.
\89\ See NOPR, 157 FERC ] 61,122 at P 50.
---------------------------------------------------------------------------
42. The Commission also proposed that if the interconnection
customer \90\ disables its governor or equivalent controls for any
reason, it shall notify the transmission provider's system operator, or
its designated representative, and shall make Reasonable Efforts \91\
to return the governor or equivalent controls to service as soon as
practicable.\92\ In addition, the Commission proposed that the
interconnection customer must provide the status and settings of the
governor or equivalent controls to the transmission provider upon
request.\93\
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\90\ The phrase ``interconnection customer'' shall have the
meaning given it in the definitional sections of the pro forma LGIA
and pro forma SGIA.
\91\ The pro forma LGIA and pro forma SGIA state that reasonable
efforts ``shall mean, with respect to an action required to be
attempted or taken by a Party under the Standard Large Generator
Interconnection Agreement, efforts that are timely and consistent
with Good Utility Practice and are otherwise substantially
equivalent to those a Party would use to protect its own
interests.'' Pro forma LGIA Art. 1 (Definitions). Pro forma SGIA
Attachment 1 (Glossary of Terms).
\92\ NOPR, 157 FERC ] 61,122 at P 52, proposed Section 9.6.4 of
the pro forma LGIA and Section 1.8.4 of the pro forma SGIA.
\93\ Proposed Section 9.6.4.1 of the pro forma LGIA and 1.8.4.1
of the pro forma SGIA.
---------------------------------------------------------------------------
2. Comments
a. Whether To Include Operating Requirements for Primary Frequency
Response in the Pro Forma LGIA and Pro Forma SGIA
43. Several commenters support the NOPR proposal to include
operating requirements (i.e., droop, deadband, and timely and sustained
response) in the pro forma LGIA and pro forma SGIA,\94\ while other
commenters either object to specific, uniform governor control setting
requirements, prefer a market-based approach, or seek limited or full
exemptions based on unique operating characteristics.\95\ Several
commenters agree that a maximum 5 percent droop and 0.036
Hz deadband for newly interconnecting generating facilities is
technically feasible.\96\
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\94\ APPA et al., AWEA, Bonneville, California Cities,
Competitive Suppliers, First Solar, Idaho Power (for generating
facilities larger than 10 MW), ISO-RTO Council, NERC, PG&E, SVP, and
WIRAB state that they either support or do not object to the
inclusion of the proposed operating requirements in the pro forma
LGIA and pro forma SGIA.
\95\ AES Companies; API; EEI; ELCON; ESA; MISO TOs; R St.
Institute; SoCal Edison; NRECA; and Xcel.
\96\ See, e.g., AWEA Comments at 4; Bonneville Comments at 3;
ISO-RTO Council Comments at 4-5; NERC Comments at 6; NRECA Comments
at 2-3.
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44. Among those supporting the proposed operating requirements,
NERC asserts that the ``proposed minimum operating conditions should
help ensure that frequency response capability is installed as well as
available and ready to respond, regardless of the mix of resources in
the dispatch,'' and ``should lead to tighter control and frequency
stability.'' \97\ ISO-RTO Council states that, absent unique local
requirements such as lower and more responsive droop values in some
remote areas of the grid, NERC's guidelines provide a sound baseline
and are consistent with current requirements in some regions, including
ISO New England, Inc. (ISO-NE), New York Independent System Operator,
Inc. (NYISO), and PJM Interconnection, L.L.C. (PJM).\98\ While it
supports the NOPR proposal, WIRAB also notes the relevance of regional
differences, and recommends that the Commission ensure that NERC and
the Regional Entities continue to monitor frequency response capability
in each region and develop best practices that highlight regional
differences in the electricity resource mix and the need for primary
frequency response.\99\ Further, WIRAB suggests that NERC and the
Regional Entities periodically reevaluate the required maximum droop
and deadband settings.\100\
---------------------------------------------------------------------------
\97\ NERC Comments at 5.
\98\ ISO-RTO Council Comments at 4-5.
\99\ WIRAB Comments at 3.
\100\ Id.
---------------------------------------------------------------------------
45. While it disagrees with a general mandate for primary frequency
response capability, in the event the Commission proceeds with a
requirement for new generating facilities to install primary frequency
response capability, NRECA supports the specific proposed operating
requirements.\101\
---------------------------------------------------------------------------
\101\ NRECA Comments at 2.
---------------------------------------------------------------------------
46. Some commenters express concern that uniform, specific governor
control settings in the pro forma LGIA and pro forma SGIA may fail to
account for regional differences and unique operating characteristics
of certain generating facilities and resource types, and could add
unnecessary costs. These commenters assert that the pro forma LGIA and
pro forma SGIA should only obligate new generating facilities to
install and maintain governors or equivalent controls, and not
establish specific operating requirements that
[[Page 9644]]
must be used.\102\ While supporting revisions to the pro forma LGIA and
pro forma SGIA to obligate newly interconnecting generators to install
governors or equivalent controls to provide primary frequency response,
EEI opposes including operating requirements. EEI asserts that tariffs,
rather than interconnection agreements, are a more effective means of
establishing operating requirements, since there are significant
differences among generating facility types and interconnections as
well as cost considerations, and because interconnection agreements
``do not provide the necessary controls to ensure compliance.'' \103\
EEI further states that operating requirements for new generating
facilities are better determined by individual balancing authorities on
an as-needed basis or through voluntary guidance from NERC.\104\ EEI
also requests that, rather than mandating specific operating
requirements, the Commission conduct a series of regional technical
conferences to ``allow for a more holistic evaluation of all [essential
reliability services]'' \105\ and provides details regarding the
proposed focus and scope of such conferences.\106\
---------------------------------------------------------------------------
\102\ See, e.g., AES Companies Comments at 6; EEI Comments at 8;
MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel
Comments at 7.
\103\ EEI Comments at 9, 11.
\104\ Id. at 11-12.
\105\ Id. at 12.
\106\ Id. at 4, n.5.
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47. MISO TOs object to ``rigid standards that do not allow for
changes in technology or in the applicable NERC standards or
guidelines.'' \107\ Rather, MISO TOs contend that flexibility can be
achieved through a generic requirement for appropriate settings
consistent with good utility practices. MISO TOs believe this approach
would minimize the need to modify the pro forma LGIA and pro forma SGIA
and expedite the implementation of needed changes for primary frequency
response.\108\ AES Companies also oppose the proposed operating
requirement for droop and deadband settings, and believe that this
requirement should not be a uniform standard that is applied to all new
generating facilities.\109\ AES Companies assert that NERC provides a
primary frequency control guideline rather than a Reliability Standard
because the guideline may need to differ based on the type of
generating facility.\110\
---------------------------------------------------------------------------
\107\ MISO TOs Comments at 9.
\108\ Id. at 11.
\109\ AES Companies Comments at 6.
\110\ Id.
---------------------------------------------------------------------------
48. While it generally agrees with the specific proposed droop and
deadband settings, NRECA supports allowing flexibility in the
requirements ``to the extent new generating facilities have differing
operating, technical or other characteristics which make compliance
with these standardized requirements unduly burdensome or impossible.''
\111\ APS, MISO TOs, SoCal Edison, Xcel and NYTOs add that the
Commission should defer to balancing authorities or transmission
providers to establish specified operating requirements for governor or
equivalent controls.\112\ Xcel states that regional system differences
could justify different primary frequency response standards.\113\
While the Commission should require that primary frequency response
capabilities be installed on all new facilities, any final action
should be flexible enough to allow for regional differences.\114\
---------------------------------------------------------------------------
\111\ NRECA Comments at 3.
\112\ APS Supplemental Comments at 5-6; MISO TOs Comments at 2;
SoCal Edison Comments at 3; Xcel Comments at 7; NYTOs Supplemental
Comments at 3-4.
\113\ Xcel Comments at 7.
\114\ Id.
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49. Some commenters that oppose including the proposed operating
requirements in the pro forma LGIA and pro forma SGIA state that
market-based procurement of primary frequency response service (in
regions of the country with organized markets) would better ensure that
the right amount and quality of primary frequency response service is
available at a lower cost to consumers.\115\ Also, NRECA is concerned
that the costs of the Commission's proposal could outweigh the
reliability benefits and delay the development of the types of
alternative technologies supported by the Commission.\116\
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\115\ See, e.g., AES Companies Comments at 9; API Comments at 4;
ELCON Supplemental Comments at 12, in support of R St Institute's
Comments; Public Interest Organizations Comments at 2; R St
Institute Comments at 4; SDG&E Comments at 5-6.
\116\ NRECA Comments at 3.
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b. Whether To Incorporate a Reference to a Future NERC Reliability
Standard in the Pro Forma LGIA and Pro Forma SGIA
50. ISO-RTO Council asserts that revisions to the pro forma LGIA
and pro forma SGIA should account for the possibility that NERC may
develop a reliability standard with more stringent specific droop and
deadband parameters, and as a result, the pro forma LGIA and pro forma
SGIA should be written to allow for this eventuality without a need to
amend the pro forma agreements.\117\ ISO-RTO Council asserts that a
possible future reliability standard with more stringent droop and
deadband parameters should supersede the pro forma interconnection
requirements.\118\ Specifically, ISO-RTO Council recommends that the
Commission require new generating facilities to comply with the more
stringent of the following requirements: (1) A maximum 5 percent droop
and 0.036 Hz deadband parameter and a droop parameter to be
based on the nameplate capability of the unit and linear in operating
range between 59 to 61 Hz as proposed in the NOPR; or (2) an approved
NERC Reliability Standard providing for more stringent parameters.\119\
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\117\ ISO-RTO Council Comments at 5.
\118\ Id.
\119\ Id. at 5-6.
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c. Requirements for Droop and Deadband
51. Some commenters question the NOPR proposal to base a generating
facility's droop parameter on its nameplate capacity. EEI asserts that
the proposal is problematic because the mandated response from
generating facilities is based on MW and Reactive Curves, and not mega
volt-ampere (MVA) nameplate ratings.\120\ Similarly, ISO-RTO Council
urges the Commission to consider that nameplate capability of a unit
may not be consistent with the rated capacity of a generating facility
for purposes of obtaining interconnection service or for participation
in an organized market.\121\ In addition, ISO-RTO Council believes that
the Commission should clarify that efficiency improvements to a
resource increasing its output (e.g., duct burners that allow for
increased output from a steam generator) should be considered when
calculating a generating unit's droop parameter.\122\
---------------------------------------------------------------------------
\120\ EEI Comments at 14.
\121\ ISO-RTO Council Comments at 6.
\122\ Id.
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52. While it supports the NOPR proposal for the droop parameter to
be linear in the operating range between 59 to 61 Hz, WIRAB recommends
that the Commission allow generating facilities to use faster, non-
linear settings over the proposed linear operating range.\123\ WIRAB
explains that a linear setting over the proposed operating range will
result in a 5 percent droop across the entire range, but that non-
linear droop parameters may lead to faster responses.\124\ More
specifically, WIRAB explains that rather than a linear 5 percent droop
across the entire operating range, ``nonlinear or
[[Page 9645]]
piecewise droop parameters,'' such as a 5 percent droop between 60.036
and 61.000 Hz and a 3 percent droop between 59.964 and 59.000 Hz, ``may
help to restore system frequency to normal faster and improve system
resiliency.'' \125\ On the other hand, EEI recommends that the
Commission not include in the pro forma interconnection agreements the
proposed requirement for the droop characteristic to be linear in the
operating between 59 to 61 Hz.\126\ In support of its position, EEI
contends that: (1) The proposed frequency range includes the deadband,
where governors do not operate; and (2) actual generating facility
response to frequency deviations may not be linear.\127\
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\123\ WIRAB Comments at 7.
\124\ Id.
\125\ Id.
\126\ EEI Comments at 14-15, 17.
\127\ Id. at 14.
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53. Regarding deadband parameters, NERC suggests that the
Commission consider replacing the proposed requirements with the NERC
Primary Frequency Control Guideline's recommendation \128\ concerning
the implementation of the deadband within the droop curve.\129\
Specifically, NERC recommends that deadbands should be implemented
without a step to the droop curve, i.e., once frequency deviates
outside the deadband, then change in the generating facility's MW
output starts from zero and then proportionally increases with the
input signal (i.e., frequency).\130\
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\128\ NERC Primary Frequency Control Guideline at 6.
\129\ NERC Comments at 6.
\130\ Id.
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d. Requirements for the Status and Settings of the Governor or
Equivalent Controls
54. NERC recommends that the Commission require the interconnection
customer to provide the status and settings of the governor or
equivalent controls and plant level controls not only to the
transmission provider (or its designated system operator) but also to
the relevant balancing authority upon request, and notify the balancing
authority when it needs to take the governor or equivalent controls and
plant level controls out of service.\131\ In support, NERC asserts
that, as the entity with a compliance obligation under Reliability
Standard BAL-003-1.1 for providing frequency response, the balancing
authority needs to know the status and settings of the governor or
equivalent controls and plant level controls in order to assess whether
there is an appropriate amount of frequency response available.\132\
NERC explains that providing this information to the balancing
authority would support efforts to help ensure sufficient frequency
response and compliance with Reliability Standard BAL-003-1.1.\133\
---------------------------------------------------------------------------
\131\ Id.
\132\ Id. at 6-7.
\133\ Id.
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55. Regarding the disabling of an interconnection customer's
governor or equivalent controls, Bonneville asserts that the proposed
revisions to the pro forma LGIA and pro forma SGIA appear to give the
interconnection customer complete discretion to take its governor or
equivalent controls out of service, provided it gives the transmission
provider notice.\134\ To ensure the availability of frequency response
when the balancing authority needs it, Bonneville suggests that such
discretion be limited to operational constraints, ``including, but not
limited to, ambient temperature limitations, outages of mechanical
equipment, or regulatory requirements.'' \135\
---------------------------------------------------------------------------
\134\ Bonneville Comments at 4.
\135\ Id. at 4-5.
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3. Commission Determination
a. Whether To Include Operating Requirements for Primary Frequency
Response in the Pro Forma LGIA and Pro Forma SGIA
56. We disagree with commenters that argue the Commission should
not establish minimum uniform operating requirements for primary
frequency response.\136\ Instead, we find that the establishment of
minimum uniform operating requirements for all newly interconnecting
generating facilities is preferable to the fragmented and inconsistent
primary frequency response settings currently in place throughout the
Eastern and Western Interconnections.\137\ Assessments by NERC's
Essential Reliability Services Task Force demonstrate that a lack of
uniform, mandatory primary frequency response requirements has created
the opportunity for generator owners/operators to implement operating
settings that undermine the purpose and intent of Article 9.6.2.1 of
the pro forma LGIA to promote and ensure the adequate provision of
primary frequency response.\138\ Article 9.6.2.1 of the pro forma LGIA
requires a generating facility to operate its speed governors and
voltage regulators in automatic operation mode when the facility is
capable of such operation. Further, as the Commission observed in the
NOPR, ``[w]hile technological advancements have enabled wind and solar
generating facilities to now have the ability to provide primary
frequency response, this functionality has not historically been a
standard feature that was included and enabled on non-synchronous
generating facilities.'' \139\ Nothing in the record indicates that the
Commission's observation was incorrect.
---------------------------------------------------------------------------
\136\ See, e.g., AES Companies Comments at 6; EEI Comments at 8;
MISO TOs Comments at 10-11; SoCal Edison Comments at 2-3; Xcel
Comments at 7.
\137\ The ERCOT Interconnection has uniform minimum requirements
for primary frequency response, as generating facilities in Texas
Reliability Entity Inc. are required to comply with the requirements
of Regional Reliability Standard BAL-001-TRE-01.
\138\ See NOPR, 157 FERC ] 61,122 at P 8. There, the NOPR
explains that a 2010 NERC survey found that ``only approximately 30
percent of generators in the Eastern Interconnection provided
primary frequency response, and that only approximately 10 percent
of generators provided sustained primary frequency response. This
suggests that many generators within the Interconnection disable or
otherwise set their governors or outer-loop controls such that they
provide little to no primary frequency response.''
\139\ Id. P 13.
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57. We believe it is necessary to make these changes to the pro
forma LGIA and pro forma SGIA now in order to ensure that the future
generation mix will be capable of providing primary frequency response,
and to arrest the general long-term declining trend for this essential
reliability service. Adopting these requirements now is more prudent
than waiting until the lack of primary frequency response undermines
grid reliability, a point acknowledged by NERC's Essential Reliability
Services Task Force.
58. Accordingly, we find that it is just and reasonable to include
the proposed operating requirements of a maximum droop setting of 5
percent and deadband setting of 0.036 Hz for primary
frequency response in the pro forma LGIA and pro forma SGIA. We
acknowledge that the needs of individual regions and balancing
authority areas may warrant the adoption of different operating
requirements in the future.\140\ Therefore, the operating requirements
for the pro forma LGIA and pro forma SGIA we adopt here are minimum
interconnection requirements for new generating facilities based on the
[[Page 9646]]
Primary Frequency Control Guideline developed by NERC through a broad-
based stakeholder process.\141\ NERC's Primary Frequency Control
Guideline ``reflect[s] the most advanced set of continent-wide best
practices and information available in support of frequency response
capability.'' \142\
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\140\ See, e.g., Order No. 827, FERC Stats. & Regs. 31,385
(``Due to technological advancements, the cost of providing reactive
power no longer represents an obstacle to the development of wind
generation.''). See also Order No. 828, 156 FERC ] 61,062 at P 8
(modifying the pro forma SGIA to require interconnecting small
generating facilities to ride through abnormal frequency and voltage
events and not disconnect during such events because ``the impact of
small generating facilities on the grid has changed.'').
\141\ The Preamble to NERC's Primary Frequency Control Guideline
states that ``[t]hese guidelines are coordinated by the technical
committees and include the collective experience, expertise and
judgment of the industry. The objective of this reliability
guideline is to distribute key best practices and information on
specific issues critical to maintaining the highest levels of BES
reliability.'' See NERC Primary Frequency Control Guideline at 1.
\142\ NERC Comments at 6.
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59. We disagree with the view of NRECA that this action is
premature because, at present, primary frequency response at the
Interconnection level may be acceptable.\143\ Rather, we find, as
stated by NERC, that increasing levels of generating facilities without
primary frequency response capability, combined with the retirement of
those generating facilities that have traditionally provided primary
frequency response, ``has contributed to the decline in primary
frequency response.'' \144\ Further, we agree with NERC's Essential
Reliability Services Task Force, which concluded that it is prudent and
necessary to ensure that the future generation mix includes primary
frequency response capabilities and recommends that all new generators
support the capability to manage frequency.\145\
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\143\ NRECA Comments at 7.
\144\ NERC Comments at 5.
\145\ Essential Reliability Services Task Force Measures Report
at vi.
---------------------------------------------------------------------------
60. AES Companies and MISO TOs contend that NERC ``provides
guidelines rather than standards because these guidelines may need to
differ based on the type of resource,'' \146\ and that NERC's Primary
Frequency Control Guideline was adopted rather than a Reliability
Standard because ``there are many current and anticipated reasons to
deviate from'' the Guideline.\147\ We disagree and are persuaded
instead by NERC and other commenters that minimum requirements are
needed.\148\
---------------------------------------------------------------------------
\146\ AES Comments at 6.
\147\ MISO TOs Comments at 11.
\148\ See, e.g., Bonneville Comments at 3; NERC Comments at 5;
ISO-RTO Council Comments at 4-5.
---------------------------------------------------------------------------
61. We find ample support in the record to support this approach.
For example, in its comments on the NOPR, NERC states that ``the
Commission's proposed revisions to the pro forma interconnection
agreements are consistent with the results of recent NERC reliability
assessment recommendations.'' \149\ Further, NERC supports the
Commission's proposal, stating that ``the NOPR's proposed minimum
operating conditions should help ensure that frequency response
capability is installed as well as available and ready to respond,
regardless of the mix of resources in the dispatch'' and notes its
support for including the proposed droop and deadband settings in the
pro forma LGIA and pro forma SGIA.\150\
---------------------------------------------------------------------------
\149\ NERC Comments at 5.
\150\ Id. at 5-6.
---------------------------------------------------------------------------
62. We disagree with EEI's assertion that the primary frequency
response operating requirements should not be included in the pro forma
LGIA and pro forma SGIA because the pro forma interconnection
agreements lack ``the necessary controls to ensure compliance.'' \151\
While this final action does not establish specific compliance
procedures for new generating facilities, transmission providers are
not prohibited from proposing such procedures in a FPA section 205
filing.\152\ Also, the pro forma LGIA and pro forma SGIA contain
Commission-approved directives that are legally enforceable
obligations.\153\ In any event, EEI's suggestion that transmission
providers would neither detect nor address possible interconnection
customer non-compliance with the new operating requirements is
speculative and without support in the record.
---------------------------------------------------------------------------
\151\ EEI Comments at 11.
\152\ 16 U.S.C. 824d (2012).
\153\ See NSTAR Elec. & Gas Corp. v. FERC, 481 F.3d 794, 800
(D.C. Cir. 2007).
---------------------------------------------------------------------------
63. EEI, MISO TOs, and SoCal Edison request that the Commission not
include the proposed operating requirements in the pro forma LGIA and
pro forma SGIA, but instead defer to transmission providers or
balancing authorities to establish operating requirements addressing
reliability needs identified in regional studies.\154\ For the reasons
discussed above, we find that it is prudent to establish minimum
uniform operating requirements as the foundational element of a
framework for ensuring the adequacy and timeliness of primary frequency
response. However, as noted immediately below and discussed in more
detail in Section II.I below, the Commission establishes, with an
addition and clarification, methods for proposing variations to this
final action.\155\
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\154\ EEI Comments at 12; MISO TOs Comments at 9; SoCal Edison
Comments at 3.
\155\ See P 233 below, describing the following variation
methods: (1) Variations based on Regional Entity reliability
requirements; (2) variations that are ``consistent with or superior
to'' the final action; and (3) ``independent entity variations''
filed by RTOs/ISOs.
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64. While we are establishing uniform operating requirements, we
also note that there is flexibility built into both the requirements
themselves and the Commission's processes. First, we clarify that the
requirements we adopt herein are minimum requirements. Thus, if an
interconnection customer wishes to implement more stringent deadband
and droop settings, it may do so.\156\ Second, as also discussed in the
next section, we have clarified the final action to allow for the
possibility of a NERC Reliability Standard that has more stringent
parameters than the requirements adopted here. Third, as discussed in
Section II.I below, we continue the Commission's historic practice of
allowing RTOs/ISOs to propose independent entity variations, as well as
permitting other transmission providers to propose changes that are
``consistent with or superior to'' the pro forma language. Finally, in
the event of a unique circumstance affecting specific resources, the
transmission provider may file a non-conforming LGIA or SGIA, or the
interconnection customer may request that the transmission provider
file an unexecuted LGIA or SGIA.
---------------------------------------------------------------------------
\156\ See NOPR, 157 FERC ] 61,122 at P 8 (``The Commission notes
that these proposed requirements are minimum requirements;
therefore, if a new generating facility elects, in coordination with
its transmission provider, to operate in a more responsive mode by
using lower droop or tighter deadband settings, nothing in these
requirements would prohibit it from doing so'').
---------------------------------------------------------------------------
65. Regarding EEI's request to conduct regional conferences, we do
not believe that they are necessary at this time since: (1) The
Commission has determined that minimum operating requirements are
appropriate to include in the pro forma LGIA and pro forma SGIA; and
(2) EEI's request to focus on other essential reliability services
besides primary frequency response is beyond the scope of this
proceeding.
66. Comments that reference compensation in lieu of including
uniform operating requirements in the pro forma LGIA and pro forma SGIA
are addressed below in Section II.E.
b. Whether To Include a Reference to a Future NERC Reliability Standard
in the Pro Forma LGIA and Pro Forma SGIA
67. The Commission is persuaded by ISO-RTO Council's request to
include in the pro forma LGIA and pro forma SGIA provisions that
address any future NERC Reliability Standard that provides for more
stringent parameters. The Commission agrees that the pro forma LGIA and
pro forma SGIA (as applied to newly interconnecting generation
facilities) should be written to allow for
[[Page 9647]]
the adoption of a future Reliability Standard with stricter operating
requirements (droop and deadband parameters) without a need to further
amend interconnection agreements.
68. Accordingly, as discussed below, we are modifying the NOPR
proposal to allow for the possibility of a future NERC Reliability
Standard that includes equivalent or more stringent operating
requirements for droop, deadband, and/or timely and sustained response
that would supersede the operating requirements for droop, deadband,
and timely and sustained response adopted in this final action. We
believe this approach will provide for the harmonization of the
reliability-related provisions of the pro forma LGIA and pro forma SGIA
with any future Reliability Standard, and will avoid potential
conflicts between Reliability Standards and tariff provisions.\157\
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\157\ See 18 CFR 39.6 (2017). This regulation requires the
Commission to issue an order within 60 days, unless it otherwise
orders, following notification of a conflict between a Reliability
Standard and any function, rule, order, tariff, rate schedule or
agreement accepted, approved, or ordered by the Commission. If the
Commission determines a conflict exists it will either direct the
Transmission Organization to file a modification of the function,
rule, order, tariff, rate schedule or agreement under FPA section
206 or the Electric Reliability Organization to file a modification
to the conflicting Reliability Standard.
---------------------------------------------------------------------------
69. We clarify that interconnection customers that are required to
comply with this final action will be required to do so until such time
as the Commission approves a NERC Reliability Standard with equivalent
or more stringent parameters.\158\ If the Commission approves such a
NERC Reliability Standard, interconnection customers subject to this
final action will be required to comply with the operating requirements
of the Reliability Standard if it applies to them. However,
interconnection customers that are not Applicable Entities of the
Reliability Standard will continue to be required to comply with the
operating requirements contained within the pro forma LGIA and pro
forma SGIA as adopted in this final action.
---------------------------------------------------------------------------
\158\ For example, such a Reliability Standard may have
requirements for tighter droop (maximum 4 percent droop) and/or
deadband settings (e.g., 0.017 Hz).
---------------------------------------------------------------------------
c. Requirements for Droop and Deadband
70. We adopt the NOPR proposal to require newly interconnecting
generating facilities to install, maintain, and operate a governor or
equivalent with a maximum 5 percent droop and 0.036 Hz
deadband and for the droop characteristic to be based on the nameplate
capacity.
71. As a threshold matter for this requirement, we clarify the term
``nameplate capacity.'' Some commenters raise concerns with the
proposal to base the droop parameter on the nameplate capacity of a
generating facility.\159\ EEI asserts that basing droop characteristics
on nameplate capacity is problematic since ``resource response is based
on MW and Reactive curves, and not MVA nameplate ratings.'' \160\ In
response to this concern, we clarify that the use of the term
``nameplate capacity'' refers to the maximum MW rating of the facility
as defined by the Energy Information Administration (EIA).\161\ We note
that EIA's definition of ``nameplate capacity'' utilizes units of MWs,
not MVAs as suggested by EEI. In response to ISO-RTO Council's request
for clarification on whether efficiency improvements to a generating
facility that increase its output should be factored into the
calculation of the droop parameter,\162\ we clarify that if a
modification to a generating facility causes its nameplate capacity to
increase or decrease, then droop parameter should be based on the
updated nameplate capacity value.
---------------------------------------------------------------------------
\159\ EEI Comments at 14; ESA Comments at 3-4.
\160\ EEI Comments at 14.
\161\ EIA defines nameplate capacity as ``[t]he maximum rated
output of a generator, prime mover, or other electric power
production equipment under specific conditions designated by the
manufacturer. Installed generator nameplate capacity is commonly
expressed in MW and is usually indicated on a nameplate physically
attached to the generator.'' See EIA Glossary, https://www.eia.gov/tools/glossary/index.php?id=G.
\162\ ISO-RTO Council Comments at 6.
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72. The droop parameter is historically based on the percent change
in frequency that would cause a 100 percent change in valve or gate
position. This has been translated to the percent change in frequency
that would cause a 100 percent change in power output, where a 100
percent change in power output is equivalent to the generator's
nameplate capacity. The droop parameter also represents the slope of
the MW response in proportion to the frequency deviation.
73. By requiring the droop parameter to be based on nameplate
capacity, the Commission intends for a generating facility's expected
MW response to frequency deviations to be a percentage of its nameplate
capacity, and proportional to the magnitude of the frequency deviation.
In particular, the magnitude of a generating facility's MW response to
a frequency deviation will depend both on its nameplate capacity and on
the magnitude of the frequency deviation. Generating facilities with
larger nameplate capacities will provide more MW of primary frequency
response per Hz of Interconnection frequency error compared to
generating facilities with an equivalent percent droop parameter that
have lower nameplate capacities. Accordingly, nameplate capacity is the
``basis'' of the droop parameter since this value will be used to
calculate the expected proportional MW response to frequency
deviations.
74. ISO-RTO Council points out that the nameplate capacity of a
generating facility may not be consistent with its rated capacity for
the purposes of obtaining interconnection service or for participation
in an organized market. In addition, we recognize that during some
operating conditions, the maximum steady state operating limit (e.g.,
maximum sustainable MW limit) of a generating facility may be less than
its nameplate capacity. Therefore, we clarify that for the purposes of
calculating the expected amount of primary frequency response that is
provided in response to frequency deviations, the calculation should
still be based on a generating facility's full nameplate capacity even
if the level of requested interconnection service or the steady state
operating limit is below that nameplate capacity. We find that this
approach is consistent with EPRI's statement that the droop setting is
historically based on the percent change in frequency that would cause
a 100 percent change in power output (where a 100 percent change in
power output is equivalent to the nameplate capacity).\163\ As an
example, in the case of a generating facility with a 5 percent droop,
as the Interconnection's frequency error changes from 0 to 3 Hz and as
the system frequency transitions outside of the deadband parameter, the
expected change in the generating facility's MW output should range
from 0 MW to full nameplate capacity.
---------------------------------------------------------------------------
\163\ EPRI Supplemental Comments at 5.
---------------------------------------------------------------------------
75. We clarify that this final action will not require a generating
facility that responds to frequency deviations to provide and sustain a
value of primary frequency response that causes its MW output to exceed
its maximum steady state operating limit.\164\ For example, under-
frequency conditions outside of the deadband parameter would result in
an automatic increase in the generating facility's MW output. However,
if the calculated incremental MW value that would be provided as
primary
[[Page 9648]]
frequency response per the droop parameter would cause the generating
facility to exceed its maximum steady state operating limit, the
interconnection customer would be permitted to limit the increase in
the generating facility's MW output such that its MW output (after
primary frequency response has been provided) does not exceed its
maximum steady state operating limit, since doing so may cause
facility-level reliability concerns. Should a generating facility's
maximum operating limit per its interconnection agreement be less than
its nameplate capacity, nothing in this final action would require an
interconnection customer to violate the terms of its interconnection
agreement. In such a situation, an interconnection customer would be
permitted to limit the increase in the generating facility's MW output
such that its MW output does not exceed the maximum operating limit as
described in the interconnection agreement.
---------------------------------------------------------------------------
\164\ For example, a generating facility's maximum steady state
operating limit may be capped at the MW level of interconnection
service requested. Or, during certain periods of an operating year,
ambient temperature conditions reduce the maximum sustainable MW
output level to below nameplate capacity.
---------------------------------------------------------------------------
76. Similarly, over-frequency conditions would result in an
automatic reduction in a generating facility's MW output. However, if
the calculated value of primary frequency response would cause the
facility's MW output to drop below its minimum operating MW limit, an
interconnection customer will be permitted to limit the decrease in the
facility's MW output such that the facility does not operate below its
minimum steady state operating limit.
77. In addition, we are persuaded by NERC's suggestion to require
the deadband parameter to be implemented without a step to the droop
curve. We note that NERC's Primary Frequency Control Guideline
references a 2013 IEEE Power & Energy Society (IEEE-PES) Technical
Report stating that a droop curve (with a deadband) can be implemented
in a generator governor in two possible ways: ``Stepped'' or ``non-
stepped.'' \165\ In its report, IEEE-PES points out that these two
methodologies of implementing the deadband parameter can potentially
have significantly different results in the response of a generating
facility's governor control system to changes in system frequency.\166\
According to IEEE-PES, if the deadband is implemented under the stepped
approach, as soon as system frequency transitions outside of the
deadband parameter (e.g., 0.036 Hz), the generating
facility will experience a sudden spike (increase or decrease) in its
MW output, which IEEE-PES warns can be undesirable.\167\ To account for
this issue, NERC recommends in its Primary Frequency Control Guideline
\168\ and its comments to the NOPR \169\ that the deadband should be
implemented without a step to the droop curve. Under the non-stepped
approach of implementing the deadband parameter, once frequency
transitions outside of the deadband, the incremental change in the
generating facility's MW output will start from zero and then increase
linearly to the generating facility's nameplate capacity and in
proportion to the Interconnection's frequency error.\170\
---------------------------------------------------------------------------
\165\ NERC Primary Frequency Control Guideline at 6, referencing
Dynamic Models for Turbine-Governors in Power System Studies at
Appendix B: Deadband, IEEE-PES (Jan 2013), http://sites.ieee.org/fw-pes/files/2013/01/PES_TR1.pdf (IEEE-PES Report).
\166\ IEEE-PES Report at Appendix B.
\167\ Id.
\168\ NERC Primary Frequency Control Guideline at 6.
\169\ NERC Comments at 6.
\170\ Id.
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78. In consideration of this additional information, we agree with
NERC and modify the NOPR proposal to require the deadband parameter to
be implemented without a step. Accordingly, we are requiring the droop
curve to be implemented in a manner such that as frequency transitions
outside of the deadband (both for under-frequency and over-frequency
conditions), the generating facility's expected MW response should
start from 0 MW and increase linearly to the nameplate capacity of the
generating facility, as the Interconnection's frequency error changes
from 0 Hz to the generating facility's percentage droop multiplied by
60 Hz (e.g., in the case of a 5 percent droop, this would be 3 Hz).
79. In response to EEI's concerns that: (1) The proposed frequency
range of 59 to 61 Hz includes the deadband where governors do not
operate; and (2) not all generating facilities respond in a linear
manner, we are modifying the NOPR proposal and adopt in this final
action that the droop parameter should be linear in the range of
frequencies between 59 to 61 Hz that are outside of the deadband
parameter. This is because the range of frequency values within the
deadband do not trigger the operation of the governor or equivalent
controls, and the slope of the droop curve that relates change in
frequency to change in MW output should only apply to the range of
frequencies outside of the deadband, i.e., those frequencies where the
generating facility's MW output is expected to change in proportion to
frequency deviations. Regarding EEI's concern that not all generating
facilities respond in a linear manner, we acknowledge that non-linear
responses can and may occur. However, we believe that the existence of
non-linear responses will not undermine the effectiveness of this final
action. We expect that interconnection customers will take Reasonable
Efforts to maximize and ensure their ability to provide a linear
response in accordance with the droop parameter.
80. While we agree with WIRAB that the use of non-linear or
piecewise droop parameters may lead to faster responses, we decline to
adopt WIRAB's request to, on a generic basis, require prospective
interconnection customers to implement non-linear or piecewise droop
curves. While we require the droop curve to be linear (e.g., 5 percent)
in the range of frequencies outside of the deadband between 59 to 61 Hz
(i.e., the response for both under-frequency and over-frequency
conditions should be based on a maximum 5 percent droop), consistent
with the NOPR proposal, we find that nothing in these requirements
prohibit the implementation of asymmetrical droop settings (i.e.,
different droop settings for under-frequency and over-frequency
conditions), provided that each segment has a percent droop value of no
more than 5 percent.\171\ For example, our requirements would not
prohibit the implementation of a droop curve that has a five percent
droop for over-frequency conditions (e.g., between 60.036 and 61.000
Hz) and a 3 percent droop for under-frequency conditions (e.g., between
59.964 and 59.000 Hz).\172\
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\171\ See NOPR, 157 FERC ] 61,122 at n.126.
\172\ See WIRAB Comments at 7.
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d. Requirements for the Status and Settings of the Governor or
Equivalent Controls
81. We agree with NERC that the balancing authority should know the
status and settings of the governor or equivalent controls and plant
level controls in order to assess whether there is an appropriate
amount of frequency reserve available.\173\ In addition, the Commission
agrees with NERC that providing this information to the balancing
authority ``would support [balancing authority] and [frequency response
sharing group] efforts to help ensure sufficient frequency response and
their compliance with Reliability Standard BAL-003-1.1.'' \174\
---------------------------------------------------------------------------
\173\ NERC Comments at 6-7.
\174\ Id.
---------------------------------------------------------------------------
82. Accordingly, we are modifying in this final action the NOPR
proposal to require the interconnection customer to provide its
relevant balancing authority with the status and settings of the
[[Page 9649]]
governor or equivalent controls upon request or when the
interconnection customer operates the generating facility with its
governor or equivalent controls not in service. We determine that this
is just and reasonable because it will help improve situational
awareness by helping the balancing authority assess whether there is an
appropriate amount of frequency responsive capacity online.
83. Regarding the process for an interconnection customer to
disable its governor or equivalent controls, we share Bonneville's
concern that the interconnection customer should not be allowed to
operate its generating facility with its governor or equivalent
controls not in service by merely notifying the transmission
provider.\175\ While we believe that it is not necessary to require the
interconnection customer to meet specific operational conditions (e.g.,
maintenance or outages of mechanical equipment) as a precondition to
disabling the governor or equivalent controls as Bonneville
suggests,\176\ we are modifying the NOPR proposal to provide additional
clarity on this issue.
---------------------------------------------------------------------------
\175\ Bonneville Comments at 4.
\176\ Id.
---------------------------------------------------------------------------
84. Specifically, we revise the pro forma LGIA and pro forma SGIA
to require the interconnection customer to make Reasonable Efforts to
keep outages of the generating facility's governor or equivalent
controls to a minimum whenever it is operated in parallel with the
Transmission System. The interconnection customer shall immediately
notify the transmission provider and relevant balancing authority of
its need to operate the generating facility without the governor or
equivalent controls in service.
85. Accordingly, we will modify the pro forma LGIA and pro forma
SGIA to state that when providing notice to the transmission provider
of its intent to disable its governor or equivalent controls, the
interconnection customer's notice shall include: (1) The operating
status of the governor or equivalent controls (i.e., whether it is
currently out of service or when it will be taken out of service); (2)
the reasons why the governor or equivalent controls are unable to be
operated in service; and (3) a reasonable estimate as to when the
governor or equivalent controls will be returned to service. The
interconnection customer will be required to then make Reasonable
Efforts to return its governor or equivalent controls to service as
soon as practicable and notify the transmission provider and balancing
authority when it has done so.
C. Requirement To Ensure the Timely and Sustained Response to Frequency
Deviations
1. NOPR Proposal
86. In the NOPR, the Commission proposed to prohibit all new large
and small generating facilities from taking any action that would
inhibit the provision of primary frequency response, except under
certain conditions, including but not limited to, ambient temperature
limitations, outages of mechanical equipment, or regulatory
requirements.\177\ The Commission explained that the lack of
coordination between governor and plant-level control systems can
result in premature withdrawal of primary frequency response by
allowing additional plant control systems to reverse the action of the
governor to return the unit to operating at a pre-selected target set-
point.\178\ The Commission noted that NERC's Primary Frequency Control
Guideline explains that ``in order to provide sustained primary
frequency response, it is essential that the prime mover governor,
plant controls and remote plant controls are coordinated.'' \179\
---------------------------------------------------------------------------
\177\ NOPR, 157 FERC ] 61,122 at P 49.
\178\ Id.
\179\ Id. (citing NERC Primary Frequency Control Guideline at
4).
---------------------------------------------------------------------------
87. Accordingly, the Commission proposed to require new generating
facilities that respond to frequency deviations to not inhibit primary
frequency response, such as by coordinating plant-level control
equipment with the governor or equivalent controls.\180\ In particular,
the Commission proposed to include new Sections 9.6.4.2 of the pro
forma LGIA and 1.8.4.2 of the pro forma SGIA to require that the real
power response of new large and small generating facilities ``to
sustained frequency deviations outside of the deadband setting is
provided without undue delay . . . until system frequency returns to a
stable value within the deadband setting of the governor or equivalent
controls.'' \181\
---------------------------------------------------------------------------
\180\ Id.
\181\ Id. PP 52-53.
---------------------------------------------------------------------------
2. Comments
88. Several commenters support including the proposed provisions
for timely and sustained response in the pro forma LGIA and pro forma
SGIA.\182\ NERC supports the minimum operating conditions proposed in
the NOPR because ``[s]uch requirements for the capability of `timely
and sustained response to frequency deviations' should promote
reliability and help avoid a scenario where the transforming resource
mix reduces frequency response capability.'' \183\ ISO-RTO Council
asserts that requiring primary frequency response to be sustained until
frequency returns within the deadband parameter ``is consistent with
the current requirements of PJM and ISO-NE, as well as CAISO.'' \184\
---------------------------------------------------------------------------
\182\ Bonneville Comments at 2, First Solar Comments at 4; Idaho
Power Comments at 1-2; ISO-RTO Council Comments at 5; NERC Comments
at 5-6; WIRAB Comments at 5.
\183\ NERC Comments at 5-6.
\184\ ISO-RTO Council Comments at 5.
---------------------------------------------------------------------------
89. While acknowledging the importance of timely and sustained
frequency response, EEI does not believe that such requirements should
be included in the pro forma LGIA and pro forma SGIA because ``the
requirements do not consider the resource type or available capacity in
requiring sustained response and therefore impose operating
requirements for all governors or equivalent controls.'' \185\ EEI
recommends that the Commission ``limit its modifications of the pro
forma LGIA and SGIA requirements to address resource capability (but
not operational requirements) in order to allow regional needs and
markets to address the issue of timely and sustained response for
frequency deviations.'' \186\ Also, EEI believes that individual
balancing authorities should determine operating requirements ``on an
as-needed basis or through compliance guidance'' from NERC.\187\ AES
Companies agree, asserting that it is prudent for each balancing
authority to determine appropriate criteria for timely and sustained
response, because ``the criteria for sustained and timely response may
differ from system to system due to operating conditions, resource mix
and more.'' \188\
---------------------------------------------------------------------------
\185\ EEI Comments at 9.
\186\ Id.
\187\ Id. at 12.
\188\ AES Companies Comments at 14.
---------------------------------------------------------------------------
90. EEI raises an additional concern, stating that ``requirements
to provide timely and sustained frequency response cannot be
implemented in a manner that is fair and non-discriminatory'' because
interconnection agreements ``do not provide the necessary controls to
ensure compliance . . . [or] effectively or fairly ensure compensation
to those entities providing this support.'' \189\ EEI states that
without a generic headroom requirement, a uniform requirement for
timely primary frequency response ``unfairly discriminates between
those
[[Page 9650]]
resources that are capable of providing timely response due to their
design or current operating status over resources that are not capable
of providing a timely response.'' \190\ As an example, EEI states that
renewables may not be able to provide a timely response to under-
frequency deviations if they are operating at capacity or due to other
technical limitations.\191\
---------------------------------------------------------------------------
\189\ EEI Comments at 11.
\190\ Id.
\191\ Id.
---------------------------------------------------------------------------
91. WIRAB and EEI recommend certain modifications to the NOPR
proposal for timely and sustained response. Both recommend that the
Commission explicitly prohibit in the pro forma LGIA and pro forma SGIA
the interconnection customer from blocking or otherwise inhibiting the
ability of the governor or equivalent controls to respond.\192\
---------------------------------------------------------------------------
\192\ EEI Comments at 18-19; WIRAB Comments at 5-6.
---------------------------------------------------------------------------
92. In the NOPR, the Commission proposed to require that the real
power response of new large and small generating facilities to
sustained frequency deviations outside of the deadband setting is
provided without undue delay . . . until system frequency returns to a
stable value within the deadband setting of the governor or equivalent
controls.'' \193\ WIRAB recommends that the term ``without undue
delay'' be defined to require the generating facility to ``provide
immediate frequency response when system frequency deviates outside of
the required deadband settings, and that no grace period be allowed
that can postpone the response.'' \194\ Additionally, WIRAB recommends
that ``stable value'' be defined as the ``settled frequency response
value achieved when frequency has rebounded and settled--after hitting
the nadir--but possibly before reaching the normal frequency of 60
Hz.'' \195\ Also, WIRAB recommends that ``[o]utside controls should not
override a generator's frequency response until the system frequency
has settled.'' \196\ WIRAB states that its recommended changes would
ensure a consistent, timely, and sustained response from generating
facilities providing primary frequency response.\197\
---------------------------------------------------------------------------
\193\ NOPR, 157 FERC ] 61,122 at PP 52-53.
\194\ WIRAB Comments at 5.
\195\ Id. at 5-6. WIRAB notes that NERC describes this settled
frequency value in its Interconnection Frequency Response Obligation
calculation used in Reliability Standard BAL-003-1.1 and labels the
value ``Value B'' in the calculation. Id. at n.8.
\196\ Id. at 6.
\197\ Id. at 5.
---------------------------------------------------------------------------
93. AWEA asks the Commission to clarify that its proposed
prohibition of actions ``inhibiting'' response does not restrict the
ability of wind and other generating facilities to adjust the speed of
their response in coordination with system operators to ensure a fair
and coordinated response that best meets the needs of the system as a
whole.\198\ AWEA explains that the fast controls inherent in modern
wind turbines allow them to respond to frequency deviations more
quickly and accurately than many conventional generators, and that some
generating facilities can respond so fast that slower-responding
facilities cannot provide a coordinated response.\199\ AWEA argues that
there should be flexibility to ensure a fair and coordinated response
(i.e., allow wind generating facilities to respond more slowly than
their full design capability) that meets the needs of the system and
does not result in a disproportionate share of the response--and cost
burden--being provided by facilities that can respond more rapidly
(such as very fast-responding wind plants).\200\ Accordingly, AWEA
recommends that the Commission clarify that adjustments to the response
speed of non-synchronous generating facilities, when done to ensure
coordinated response for the system operator and fair distribution of
cost impacts across generating facility types, do not ``inhibit''
response within the meaning of the NOPR, or if it does, are within the
scope of the operational constraints permitted under the NOPR.\201\
---------------------------------------------------------------------------
\198\ AWEA Comments at 8-9.
\199\ Id.
\200\ Id. at 9.
\201\ Id.
---------------------------------------------------------------------------
3. Commission Determination
94. We determine that it is just and reasonable to include a
requirement for timely and sustained response in the pro forma LGIA and
pro forma SGIA. As stated in the NOI, premature withdrawal of primary
frequency response ``has the potential to degrade the overall response
of the Interconnection and result in a frequency that declines below
the original nadir.'' \202\ We are persuaded by the reliability
assessments performed by NERC confirming a general decline in primary
frequency response that, unless adequately addressed, could worsen as
the generation resource mix continues to evolve.\203\ The requirement
for timely and sustained response would address that decline and more
specifically would address concerns raised by NERC and others about the
premature withdrawal of primary frequency response following a system
disturbance, which is a significant concern in the Eastern
Interconnection and a somewhat smaller issue in the Western
Interconnection.\204\ This phenomenon stems from generating facilities
that do not sustain the response until system frequency returns to
within the deadband parameter; instead they withdraw the response soon
after it is provided.\205\ In adopting this requirement, we agree with
commenters who stated that there should be a clear requirement for
primary frequency response to be timely and sustained.\206\
---------------------------------------------------------------------------
\202\ See NOI, 154 FERC ] 61,117 at P 49.
\203\ See NERC Comments at 5. NERC states that it ``has
determined that increasing levels of non-synchronous resources
installed without controls that enable frequency response
capability, coupled with retirement of conventional resources that
have traditionally provided primary frequency response, has
contributed to the decline in primary frequency response'' and that
``a changing resource mix will further alter the dispatch of
resources and combinations of resources . . . potentially resulting
in systems operating states where frequency response capability
could be diminished unless a sufficient amount of frequency
responsive capacity is included in the dispatch.''
\204\ See NOI, 154 FERC ] 61,117 at PP 49-50. See also Frequency
Response and Frequency Bias Setting Reliability Standard, Notice of
Proposed Rulemaking, 78 FR 45479 (July 29, 2013), 144 FERC ] 61,057,
at PP 35-38 (2013).
\205\ In the NOI, the Commission stated that primary frequency
response withdrawal ``has the potential to degrade the overall
response of the Interconnection and result in a frequency that
declines below the original nadir.'' See NOI, 154 FERC ] 61,117 at P
49.
\206\ See, e.g., Bonneville Comments at 2; ISO-RTO Council
Comments at 5; NERC Comments at 5-6; WIRAB Comments at 6.
---------------------------------------------------------------------------
95. We are not persuaded by EEI's and AES Companies' view that
timely and sustained response requirements should be part of regional
solutions rather than be included in the pro forma LGIA and pro forma
SGIA. NERC's assessments and conclusions do not indicate that the
fundamental concerns about declining primary frequency response or the
premature withdrawal of primary frequency response are unique or
limited to individual regions. In addition, we note that frequency
response is an Interconnection-wide phenomenon. Accordingly, we find
that minimum, uniform primary frequency response requirements,
including timely and sustained response, are just and reasonable.
96. EEI comments that without a provision to ``fairly ensure
adequate compensation,'' and a mandate that each new generating
facility operate with headroom at all times, the proposed requirements
for timely and sustained primary frequency response ``cannot be
implemented in a manner that is fair and non-discriminatory.'' \207\
EEI asserts that ``requiring all resources to have a timely operating
response, but
[[Page 9651]]
failing to require necessary headroom, unfairly discriminates between
those resources that are capable of providing a timely response due to
their design or current operation status over resources that are not
capable of providing a timely response.'' \208\ We disagree. We are
imposing operating requirements on all newly interconnecting generating
facilities (with limited exemptions) but not mandating headroom or
compensation for any generating facilities. Any headroom maintained by
these facilities is not required by this final action, and does not
render our operating requirements unduly discriminatory. If future
conditions necessitate a headroom requirement, we will then consider
any appropriate compensation.
---------------------------------------------------------------------------
\207\ EEI Comments at 11.
\208\ Id.
---------------------------------------------------------------------------
97. As noted in Section II above, one of the Commission's concerns
with the current lack of clear, uniform primary frequency response
requirements is NERC's finding indicating that a number of generator
owners/operators have implemented operating settings that have
effectively removed the availability of their generating facilities
from providing timely and sustained primary frequency response (e.g.,
wide deadband settings, uncoordinated plant-level controls).\209\ The
reforms adopted in this final action, to be applied uniformly to new
generating facilities, are intended to eliminate these practices.
Accordingly, the Commission determines that the requirements are just,
reasonable and not unduly discriminatory or preferential.
---------------------------------------------------------------------------
\209\ Id. PP 8-9, 39.
---------------------------------------------------------------------------
98. Further, while it is true that generating facilities that are
operated with no headroom at the time of an under-frequency deviation
will provide little or no response in the upward direction, they will
still be available to support the reliability of the power system by
responding in the downward direction during abnormal over-frequency
system conditions. Since the timing of an abnormal frequency deviation
outside of the deadband parameter--and when a generating facility will
thus be required to respond--is unpredictable, it is possible that
these generating facilities will have operating capability in the
upward direction to respond to some abnormal under-frequency
deviations.
99. We agree with the suggestions of EEI and WIRAB to explicitly
prohibit interconnection customers from blocking or otherwise
inhibiting the governor's or equivalent controls' ability to
respond.\210\ Accordingly, as discussed below in Section II.K.3, the
Commission will modify in this final action the NOPR proposal to
require interconnection customers to not block or otherwise inhibit the
governor or equivalent controls' ability to respond.
---------------------------------------------------------------------------
\210\ EEI Comments at 16, 18-19; WIRAB Comments at 5-6.
---------------------------------------------------------------------------
100. AWEA, ESA, and WIRAB ask the Commission to clarify the
proposed timely and sustained response provisions, and their comments
raise the following questions: (1) How soon should a generating
facility begin to provide primary frequency response following a
disturbance; and (2) how long, at a minimum, should the response be
sustained?
101. Regarding how soon a generating facility should begin to
provide primary frequency response following a disturbance, the
Commission agrees with WIRAB that the definition of ``without undue
delay'' should be clarified.\211\ Accordingly, we clarify that the NOPR
proposal for generating facilities to respond ``without undue delay''
is intended to address the concern that an interconnection customer
could program an intentional delay of several seconds or minutes to
effectively avoid contributing to the support of power system
reliability following a disturbance. Following the sudden loss of
generation or load, primary frequency response must be delivered as
promptly as possible, within the physical characteristics of the
generating facility, in order to avoid, for example, Interconnection
frequency declining to a level where UFLS relays are activated or to a
lower level where generation under-speed protection relays activate,
resulting in additional generation trips or cascading outages.
Accordingly, in response to WIRAB's request to clarify when a
generating facility should respond to a frequency deviation, we will
modify the NOPR proposal and adopt in this final action the requirement
that generating facilities respond immediately after system frequency
deviates outside of the deadband parameter, to the extent that they
have available operating capability in the direction needed to correct
frequency deviation at the time of the disturbance.\212\
---------------------------------------------------------------------------
\211\ See WIRAB Comments at 5.
\212\ The Commission accepted similar tariff language proposed
by CAISO. See Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182, at
P 17 (2016) (accepting, among other things, CAISO's proposed changes
to s Section 4.6.5.1 of its tariff, which provides in pertinent part
that ``Participating Generators with governor controls that are
synchronized to the CAISO Controlled Grid must respond immediately
and automatically.'').
---------------------------------------------------------------------------
102. We agree with WIRAB that no grace period should be allowed
that can postpone the response. Accordingly, we deny AWEA's request to
coordinate response times between interconnection customers and system
operators.\213\ Instead, we require generating facilities to respond
immediately, consistent with the technical capabilities of the
generating facility and its control equipment.
---------------------------------------------------------------------------
\213\ See AWEA Comments at 8-9 (describing efforts to coordinate
the fast response times of wind facilities with system operators).
---------------------------------------------------------------------------
103. Regarding the minimum period of time that a response should be
sustained, we will not establish in this final action a minimum
timeframe in minutes that the response to frequency deviations should
be sustained since the amount of time that Interconnection frequency
remains outside of the deadband varies by event.
104. We determine that rather than using the term ``stable'' used
in the NOPR concerning the sustained response requirement, it is
preferable to require primary frequency response to be sustained until
such time that system frequency returns to a value within the deadband.
Therefore, we find that WIRAB's recommendation to adopt its definition
of ``stable value'' is moot. Accordingly, we clarify that with the
exception of certain operational constraints described in Section
9.6.4.2 of the pro forma LGIA and Section 1.8.4.2 of the pro forma
SGIA, generating facilities that respond to abnormal and sustained
frequency deviations outside of the deadband parameter are required to
provide and sustain primary frequency response until system frequency
has returned to a value within the deadband parameter. If frequency
recovers to within the deadband but suddenly deviates outside of the
deadband parameter again, the interconnection customer will be required
to provide and sustain its response until such time that frequency
returns to a value within the deadband.
105. Comments related to electric storage resources pertaining to
the timely and sustained response provisions are addressed below in
Section II.H.2.
D. Proposal Not To Mandate Headroom
1. NOPR Proposal
106. In the NOPR, the Commission clarified that the proposed
requirements did not impose a generic headroom requirement, but sought
comment on such a requirement.\214\ The Commission stated its belief
that the reliability benefits from the proposed
[[Page 9652]]
modifications to the pro forma LGIA and pro forma SGIA do not require
imposing additional costs that would result from a generic headroom
requirement.\215\
---------------------------------------------------------------------------
\214\ NOPR, 157 FERC ] 61,122 at P 51.
\215\ Id.
---------------------------------------------------------------------------
2. Comments
107. Several commenters state that the Commission should not create
a mandatory headroom requirement.\216\ Idaho Power asserts that a
generic headroom requirement is not necessary at this time.\217\ AWEA,
Public Interest Organizations, and SDG&E state that there are
significant opportunity costs involved in maintaining headroom.\218\
WIRAB adds that not every generating facility needs to provide primary
frequency response all the time; instead the decision of whether a
generating facility provides primary frequency response and the
necessary amount of headroom should be determined by economic
considerations rather than by generic requirements.\219\ EEI supports
the NOPR proposal not to include a generic headroom requirement in the
pro forma LGIA and pro forma SGIA ``since these requirements go beyond
capability (i.e., equipment specifications.)'' \220\ However, EEI also
asserts that not requiring headroom while requiring all primary
frequency responses to be timely and sustained would be discriminatory,
because all generating facilities are not capable of timely
responses.\221\ We address this assertion above in Section II.C.3.
---------------------------------------------------------------------------
\216\ EEI, Public Interest Organizations, AWEA, ESA, ISO-RTO
Council, Xcel, Idaho Power, WIRAB, NERC, First Solar.
\217\ Idaho Power Comments at 2.
\218\ AWEA Comments at 2; Public Interest Organizations Comments
at 4; SDG&E Comments at 2.
\219\ WIRAB Comments at 9.
\220\ EEI Comments at 13.
\221\ Id. at 11.
---------------------------------------------------------------------------
108. AWEA requests that the Commission consider expanding on the
NOPR proposal by finding that it would be unjust and unreasonable for a
transmission provider to impose a requirement for all generating
facilities to reserve headroom to provide primary frequency response
due to the large inefficiency and cost of such a requirement.\222\ ESA
asserts that it interprets the Commission's proposal as an explicit
prohibition against requiring interconnection customers to reserve
headroom as a condition of interconnection.\223\
---------------------------------------------------------------------------
\222\ AWEA Comments at 3.
\223\ ESA Comments at 2.
---------------------------------------------------------------------------
3. Commission Determination
109. We will not mandate a headroom requirement at this time. We
continue to believe that the reliability benefits from the proposed
modifications to the pro forma LGIA and pro forma SGIA do not require
imposing additional costs that would result from a generic headroom
requirement.\224\
---------------------------------------------------------------------------
\224\ NOPR, 157 FERC ] 61,122 at P 44.
---------------------------------------------------------------------------
110. We decline to address AWEA's request to find it unjust and
unreasonable for a transmission provider to impose a requirement for
all generating facilities to reserve headroom to provide primary
frequency response. Instead, in response to AWEA and ESA, we clarify
that this final action does not prohibit a transmission provider from
arguing to the Commission that headroom should be required as a
condition of interconnection in a particular factual circumstance and
proposing an associated compensation mechanism. We will evaluate any
such filings on a case-by-case basis. Finally, we revise proposed
Article 9.6.4 of the pro forma LGIA and Article 1.8.4 of the pro forma
SGIA to delete the following reference: ``Nothing shall require the
generating facility to operate above its minimum operating limit, below
its maximum operating limit, or otherwise alter its dispatch to have
headroom to provide primary frequency response.'' We believe that this
phrase is unnecessary and that it is clear without it that we are not
requiring headroom as a condition of interconnection.
E. Proposal Not To Mandate Compensation
1. NOPR Proposal
111. The Commission did not propose to mandate compensation related
to the new primary frequency response requirements, stating ``the
Commission has previously accepted changes to transmission provider
tariffs that similarly required interconnection customers to install
primary frequency response capability or that established specific
governor settings, without requiring any accompanying compensation.''
\225\ Further, the Commission clarified that the absence of a
compensation mandate is not intended to prohibit a public utility from
filing a proposal for primary frequency response compensation under
section 205 of the FPA.\226\
---------------------------------------------------------------------------
\225\ Id. P 55 (citing PJM Interconnection, L.L.C., 151 FERC ]
61,097 at n.58; Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182,
at PP 10-12 and 17 (2016); New England Power Pool, 109 FERC ] 61,155
(2004), order on reh'g, 110 FERC ] 61,335 (2005)).
\226\ Id.
---------------------------------------------------------------------------
2. Comments
112. Many commenters support not mandating compensation.\227\ On
the other hand, a few commenters reject the NOPR's overarching
approach, asserting instead that a market-based approach or a
centralized forward procurement process is needed.\228\ Other
commenters qualify their support of the NOPR's approach to compensation
on future efforts to establish forward procurement or market
mechanisms.\229\
---------------------------------------------------------------------------
\227\ ISO-RTO Council; WIRAB; Xcel; PG&E; APPA et al.; EEI; MISO
TOs; NRECA; California Cities; and SoCal Edison.
\228\ AES; SDG&E; API; Chelan County; R St. Institute; and CESA.
\229\ AWEA; ELCON; Public Interest Organizations; and First
Solar.
---------------------------------------------------------------------------
113. Some commenters believe that compensation issues are best
decided at the regional level.\230\ ISO-RTO Council asserts that not
mandating compensation is reasonable because ``[f]undamentally, the
costs of providing primary frequency response by all registered
generators should be viewed simply as a cost of reliable generator
operation (similar to, for example, maintenance, staffing, metering,
software, and communications).\231\ APPA et al. agrees, stating that
primary frequency response capability should be a standard feature of
new generating facilities.\232\ APPA et al. also notes that the
Commission recently recognized imposing requirements for generating
facilities with governor controls without additional compensation is a
just and reasonable condition of participation in wholesale
markets.\233\ In addition, SoCal Edison believes that the costs of
primary frequency response capability are already adequately recovered
through existing bilateral or market-based capacity contracts.\234\
---------------------------------------------------------------------------
\230\ Xcel Comments at 7; PG&E Comments at 2; EEI Comments at
11; MISO TOs Comments at 14.
\231\ ISO-RTO Council Comments at 10.
\232\ APPA et al. Comments at 6.
\233\ Id. (citing Cal. Indep. Sys. Operator Corp., 156 FERC ]
61,182 at P 17 (2016)).
\234\ SoCal Edison Comments at 4.
---------------------------------------------------------------------------
114. AWEA states that the cost of attaining primary frequency
response capability for new generators is low \235\ but asserts that
the Commission's decision not to address compensation for primary
frequency response capability in the proposed rulemaking is not a major
concern, so long as there is no headroom requirement.\236\ California
Cities compares primary frequency response with a number of
interconnection requirements for generating facilities in which the
recovery of capital costs and operating
[[Page 9653]]
expenses are not necessarily ensured.\237\ California Cities states
that developers of new generating facilities have the opportunity to
recover capital costs for primary frequency response capability in the
same ways they recover other capital costs associated with generation
resources and can factor the costs of primary frequency response into
their economic assessment of project viability under anticipated market
conditions and into their negotiations for capacity sales.\238\
---------------------------------------------------------------------------
\235\ AWEA Comments at 1.
\236\ Id. at 9.
\237\ California Cities Comments at 4.
\238\ Id.
---------------------------------------------------------------------------
115. ELCON supports not mandating compensation, expressing its
expectation that such costs should be low, observing that the
administrative costs of a compensation scheme may outweigh the costs of
providing mandated service.\239\ Further, ELCON joins APPA et al. in
noting that this is consistent with prior Commission decisions
requiring the installation of primary frequency response capability or
specifying governor settings, without mandating compensation.\240\
ELCON emphasizes that its comments regarding compensation are limited
to the currently proposed limited applicability of new requirements to
new generation facilities because a broader approach would trigger more
significant costs and should focus on market-based solutions such as
that under Order No. 819.\241\
---------------------------------------------------------------------------
\239\ ELCON Comments at 6.
\240\ Id. n.4 (citing PJM Interconnection, L.L.C., 151 FERC ]
61,097 at n.58; Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182,
at PP 10-12 and 17 (2016); New England Power Pool, 109 FERC ] 61,155
(2004), order on reh'g, 110 FERC ] 61,335 (2005)).
\241\ Id. at 7.
---------------------------------------------------------------------------
116. In support of compensation, several commenters state that the
proposed requirements are inefficient or uneconomic because, among
other points, they require new generating facilities to install and
operate a governor or equivalent controls when the necessary primary
frequency response could be provided at lower cost by another
generating facility (e.g., battery storage or existing generating
facility).\242\ These commenters believe that market-based procurement
will create opportunities for transmission providers to obtain higher-
quality frequency response at a lower cost compared to a mandatory
primary frequency response requirement for all newly interconnecting
generating facilities. Rather than the mandatory requirements proposed
in the NOPR, some commenters prefer market-based compensation to incent
the ``right'' level of primary frequency response.\243\
---------------------------------------------------------------------------
\242\ AES Companies Comments at 9; API Comments at 4; AWEA
Comments at 11; ELCON Supplemental Comments at 12, in support of R
St Institute's Comments; Competitive Suppliers Comments at 4; ESA
Comments at 6; Public Interest Organizations Comments at 2; R St
Institute Comments at 4; SDG&E Comments at 5-6 and SDG&E
Supplemental Comments at 2-3. Public Interest Organizations, in
their Comments at 5-6, refer to the need to remove settlement system
``disincentives'' to the provision of primary frequency response by
existing generators, which the Commission interprets as a request
for compensation for providing this service.
\243\ API Comments at 3-4; Chelan County Comments at 1-2; Public
Interest Organizations Comments at 6-7; R St Institute's Comments at
2-3; and SDG&E Comments at 3.
---------------------------------------------------------------------------
117. Other commenters believe that generating facilities should not
be required to provide primary frequency response without compensation
for their costs of providing the service.\244\ SDG&E asserts that the
NOPR proposals will not address the Commission's concerns regarding the
decline in primary frequency response because ``uncompensated costs are
at the root of poor historical performance.'' \245\ Further, AWEA
raises concerns that it is unjust and unreasonable to mandate that new
generation incur investment and maintenance costs to be primary
frequency response capable without being provided a real opportunity to
recover such costs.\246\ Competitive Suppliers assert that ``[a]ll
resources that provide essential reliability services such as primary
frequency response and inertia should be explicitly compensated rather
than mandating generators provide them without distinct and additional
compensation.'' \247\ Competitive Suppliers urge the Commission to
address compensation in a final rule or additional NOPR.\248\ First
Solar encourages the Commission to require compensation for the
configuration and additional communication, software and control
technologies required to operate the equipment at a solar PV generation
facility to provide essential reliability services.\249\ First Solar
believes that the Commission should also require ISOs and RTOs develop
a funding mechanism and operational and market rules to accommodate the
headroom requirements for these facilities to provide frequency
response.\250\
---------------------------------------------------------------------------
\244\ AWEA Comments at 10; ELCON Supplemental Comments at 12-13
(over longer term); Competitive Suppliers Comments at 3, 5; ESA
Comments at 6-7; First Solar Comments at 4; MISO TOs Comments at 5
(compensation should be determined regionally); and SDG&E Comments
at 3.
\245\ SDG&E Comments at 3.
\246\ AWEA Comments at 10.
\247\ Competitive Suppliers Comments at 5.
\248\ Id.
\249\ First Solar Comments at 4.
\250\ Id.
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118. ESA raises concerns that, without compensation, the primary
frequency response requirement for electric storage ``may produce
disproportionate adverse economic impacts.'' \251\ Therefore, ESA
recommends that the Commission ``direct RTOs/ISOs to use pay-for-
performance principles to price primary frequency response provision.''
\252\ ESA relies on Order No. 755, where the Commission found that
frequency regulation compensation practices that do not compensate
performance result in rates that are unjust, unreasonable, and unduly
discriminatory or preferential. ESA contends that the same argument
applies to frequency response compensation.\253\
---------------------------------------------------------------------------
\251\ ESA Comments at 4.
\252\ Id. at 6.
\253\ ESA Comments at 6-7 (citing Frequency Regulation
Compensation in Organized Wholesale Power Markets, Order No. 755,
FERC Stats. & Regs. ] 31,324, at P 2 (2011) (crossed referenced at
137 FERC ] 61,064).
---------------------------------------------------------------------------
3. Commission Determination
119. We will not mandate compensation for primary frequency
response service in this final action. We are not persuaded by comments
that assert: (1) Generating facilities should not be required to
provide a service if there is not explicit compensation; (2) market-
based compensation would be more efficient than the NOPR proposal; (3)
inertia should be compensated in this final action; and (4) that
frequency regulation compensation under Order No. 755 requires that
primary frequency response be compensated. We address each of these
points below.
120. Commenter assertions that the Commission is improperly
requiring the provision of a service without compensation are
misplaced. While we are requiring newly interconnecting generating
facilities to install equipment capable of providing frequency response
and adhere to specified operating requirements, we are not mandating
headroom, which is a necessary component for the provision of primary
frequency response service. In addition, as stated in the NOPR, ``[t]he
Commission has previously accepted changes to transmission provider
tariffs that similarly required interconnection customers to install
primary frequency response capability or that established specified
governor settings, without requiring any accompanying compensation.''
\254\ Further, we agree
[[Page 9654]]
with California Cities that there are interconnection requirements for
generating facilities in which the recovery of capital costs and
operating expenses are not necessarily ensured.
---------------------------------------------------------------------------
\254\ NOPR, 157 FERC ] 61,122 at P 55 (citing PJM
Interconnection, L.L.C., 151 FERC ] 61,097 at n.58; Cal. Indep. Sys.
Operator Corp., 156 FERC ] 61,182 at PP 10-12 and 17; New England
Power Pool, 109 FERC ] 61,155, order on reh'g, 110 FERC ] 61,335).
The Commission reiterated this approach in Indianapolis Power &
Light Company v. Midcontinent Indep. Sys. Operator, Inc., 158 FERC ]
61,107, at PP 36-37 (2017) (Indianapolis Power) (denying
Indianapolis Power's request that the Commission find MISO's Tariff
to be unjust, unreasonable, and unduly discriminatory or
preferential because it does not compensate suppliers of primary
frequency response).
---------------------------------------------------------------------------
121. On balance, we find that the record indicates that the cost of
installing, maintaining, and operating a governor or equivalent
controls is minimal.\255\ Also, the greatest cost associated with
providing primary frequency response results from maintaining headroom,
as noted by several commenters.\256\ No commenter provided any evidence
suggesting that the costs of providing primary frequency response are
greater than those indicated in the NOPR.\257\ While the Commission has
approved specific compensation for discrete services that require
substantial identifiable costs, such as for frequency regulation and
operating reserves, the Commission has not required specific
compensation for all reliability-related costs. We agree with those
commenters who observe that minimal reliability-related costs such as
those incurred to provide primary frequency response, are reasonably
considered to be part of the general cost of doing business, and are
not specifically compensated.
---------------------------------------------------------------------------
\255\ See NOPR, 157 FERC ] 61,122 at PP 62-71; see also ISO-RTO
Council Comments at 9 (stating ``the incremental cost to provide
frequency response is minimal''); ELCON Comments at 6 (citing ``the
low costs triggered by the NOPR's limited applicability to only new
generating facilities''); AWEA Comments at 1 (stating ``the cost of
attaining [primary frequency response] capability for new generators
is low.'').
\256\ See AWEA Comments at 9; Public Interest Organizations
Comments at 4.
\257\ See NOPR, 157 FERC ] 61,122 at P 41 (stating that ``small
generating facilities are capable of installing and enabling
governors at low cost in in a manner comparable to large generating
facilities.'').
---------------------------------------------------------------------------
122. With regard to requests for the Commission to mandate market-
based compensation, we are not persuaded by assertions that mandatory
market-based mechanisms for the procurement of primary frequency
response capability are just and reasonable at this time given the
record before us. While some economic efficiency may be gained from
acquiring primary frequency response from the subset of generation that
is most economically efficient at providing this service, we believe
that the time and costs of developing a market in RTO/ISO regions or
bilaterally purchasing the service in non-RTO/ISO regions should be
carefully considered. ISO-RTO Council asserts, for example, that the
administrative costs of developing and implementing market-based
compensation of primary frequency response are likely to outweigh the
incremental efficiency benefits.\258\ Similarly, SDG&E states that, to
develop a market, each RTO/ISO will have to address issues such as
developing complex software to operate the market and verifying
generator performance in sub-minute intervals, which may require the
installation of high-quality metering equipment such as phasor
measurement units.\259\ Nonetheless, an RTO/ISO may propose such an
approach upon an adequate showing under section 205, if it so chooses.
---------------------------------------------------------------------------
\258\ See ISO-RTO Council Comments at 9-10. See also ELCON
Comments at 6.
\259\ See SDG&E Comments at n.6.
---------------------------------------------------------------------------
123. With regard to Competitive Suppliers' view that the Commission
should mandate explicit compensation for inertial response, we decline
to adopt such a requirement.\260\ We recognize the reliability value of
inertial response, as it helps to slow the rate of change of frequency
during frequency deviations. In addition, very low levels of inertial
response within an Interconnection increase the risk that the speed of
primary frequency response delivery will be too slow to prevent large
frequency deviations from exceeding pre-determined thresholds for load
shedding or automatic generator trip protection. However, no commenter
asserts that inertial response trends on the Eastern and Western
Interconnections are approaching levels that could threaten
reliability. In addition, because inertial response is provided
automatically by the rotating mass of synchronous machines as system
frequency deviates and is not controllable, synchronous generating
facilities do not incur additional incremental costs to provide
inertial response. Indeed, neither Competitive Suppliers nor any other
commenter has indicated what, if any, incremental costs must be
incurred to provide inertial response. Accordingly, we conclude that
compensation for inertial response compensation is not warranted at
this time.
---------------------------------------------------------------------------
\260\ See Competitive Suppliers Comments at 5.
---------------------------------------------------------------------------
124. We disagree with ESA's contention that the treatment of
frequency regulation under Order No. 755 requires compensation of
primary frequency response in this final action. In Indianapolis Power,
the Commission rejected a similar request for primary frequency
response compensation based on Order No. 755, finding that ``Order No.
755 is inapposite, as that order involved an existing market, where the
Commission found that the frequency regulation compensation practices
of RTOs and ISOs resulted in rates that are unjust, unreasonable, and
unduly discriminatory or preferential.'' \261\ For similar reasons,
Order No. 755 is inapposite here.
---------------------------------------------------------------------------
\261\ Indianapolis Power, 158 FERC ] 61,107 at P 37.
---------------------------------------------------------------------------
125. AES and MISO TOs request that the Commission allow for the
development of primary frequency response pools, self-supply of primary
frequency response, and transferred primary frequency response
markets.\262\ We conclude that existing requirements (e.g., contracts
for frequency response service under Order No. 819,\263\ and recent
Commission action regarding transferred frequency response \264\)
already address two of these options. Also, a Frequency Response
Sharing Group under Reliability Standard BAL-003-1.1, is an option
currently available to balancing authorities.
---------------------------------------------------------------------------
\262\ AES Comments at 5; MISO TOs Comments at 11.
\263\ Third-Party Provision of Primary Frequency Response
Service, Order No. 819, FERC Stats. & Regs. ] 31,375 (2015) (cross-
referenced at 153 FERC ] 61,220).
\264\ Cal. Indep. Sys. Operator Corp., 156 FERC ] 61,182, order
on clarification, compliance, and rehearing, 158 FERC ] 61,129
(2017).
---------------------------------------------------------------------------
126. Finally, nothing in this final action is meant to prohibit a
public utility from filing a proposal for primary frequency response
compensation under section 205 of the FPA.\265\
---------------------------------------------------------------------------
\265\ See NOPR, 157 FERC ] 61,122 at P 55.
---------------------------------------------------------------------------
F. Application to Existing Generating Facilities That Submit New
Interconnection Requests That Result in an Executed or Unexecuted
Interconnection Agreement
1. NOPR Proposal
127. In the NOPR, the Commission proposed to apply the revisions to
the pro forma LGIA and pro forma SGIA to new generating facilities that
execute or request the unexecuted filing of interconnection agreements
on or after the effective date of any final action issued.\266\ The
Commission also proposed to apply the requirements to any large or
small generating facility that has an executed or has requested the
filing of an unexecuted LGIA or SGIA as of the effective date of any
final action, but that takes any action that requires the submission of
a new interconnection request on or after the effective date of any
final action.\267\ The Commission sought comment on the
[[Page 9655]]
proposed effective date, including whether the proposed application of
the requirements would be unduly burdensome.\268\
---------------------------------------------------------------------------
\266\ Id. P 54.
\267\ Id.
\268\ Id.
---------------------------------------------------------------------------
2. Comments
128. Most commenters addressing this issue agree with the proposed
effective date and applicability, with some suggesting additional
action would be helpful.\269\ While Bonneville supports the
Commission's proposed effective dates, it observes that ``if
significant modifications are made to the generating facility, the cost
of including primary frequency response capability may not add much to
the cost of the modifications themselves.'' \270\ Therefore, Bonneville
believes that the Commission should ``explore defining what constitutes
a `significant modification''' and require existing generating
facilities to include primary frequency response capability when making
one.\271\ California Cities support the Commission's proposal because
the proposal is sufficiently narrow as to only include those generating
facilities that make a substantial change.\272\
---------------------------------------------------------------------------
\269\ Idaho Power Comments at 2; WIRAB Comments at 8-9; First
Solar Comments at 4; Bonneville Comments at 3; California Cities
Comments at 3-4; ISO-RTO Council Comments at 8.
\270\ Bonneville Comments at 3.
\271\ Id.
\272\ California Cities Comments at 3-4.
---------------------------------------------------------------------------
129. Other commenters, however, believe that the NOPR proposal
should go further. ISO-RTO Council states that it ``is unaware of any
limitations that would render the Commission's proposed effective date
infeasible or unduly burdensome'' and therefore it supports the
proposed effective date.\273\ However, ISO-RTO Council suggests that
the Commission expand the application of the primary frequency response
capability and operating requirements to both conforming and non-
conforming interconnection agreements resulting from new
interconnection requests by existing generating facilities.\274\ ISO-
RTO Council explains that under the NOPR proposal, an existing
interconnection customer that ``takes an action that requires the
submission of a new interconnection request resulting in the execution
of a conforming interconnection agreement would not be obligated under
the Commission's proposed requirements because the interconnection
agreement would not be filed.'' \275\ Therefore, ISO-RTO Council
recommends that the proposed requirements apply to any existing
interconnection customer that takes any action that requires the
submission of a new interconnection request that results in the
execution of an interconnection agreement, regardless of whether the
agreement is filed, or the filing of an unexecuted interconnection
agreement after the effective date of any final action.\276\
---------------------------------------------------------------------------
\273\ ISO-RTO Council Comments at 8.
\274\ Id.
\275\ Id.
\276\ Id.
---------------------------------------------------------------------------
130. Xcel contends that the Commission's proposal does not go far
enough to ensure future generating facilities are capable of providing
primary frequency response.\277\ Xcel's concern pertains to the
possibility of a generating facility obtaining an interconnection
agreement for more generation than is initially installed. In this
situation, new generating facilities installed years after the
effective date of the final action would not be required to install
primary frequency response capability because a new interconnection
agreement for subsequent phases is not required.\278\ Therefore, Xcel
asks the Commission to consider requiring that any new generating
facility added to expand an existing large or small generating facility
more than two years after the effective date of the final action be
required to provide primary frequency response, even if no new
interconnection agreement is required.\279\
---------------------------------------------------------------------------
\277\ Xcel Comments at 6.
\278\ Id.
\279\ Id. Xcel states that this approach should not apply to an
uprate of an existing facility.
---------------------------------------------------------------------------
131. SVP raises concerns that the proposed reforms could apply to
existing generating facilities if interconnection customers amend their
interconnection agreements for minor updates involving no material
substantive changes to the interconnected facilities or to the
interconnection itself.\280\ SVP explains that as a licensee of three
hydropower projects, each with a generating capacity of less than 20
MW, SVP has for over 30 years continually procured interconnection
service for these facilities through an interconnection agreement with
PG&E.\281\ SVP states that it is coordinating with PG&E and CAISO to
reformat the existing agreements and that it may execute and file an
amended agreement after the effective date of the final action with no
material changes to the facilities or to the interconnection.\282\ SVP
seeks clarification that the proposed reforms will not apply to
existing facilities with existing interconnection agreements that
execute new form agreements if there are no material substantive
changes to the interconnected facilities or to the interconnection
itself.\283\
---------------------------------------------------------------------------
\280\ SVP Comments at 5-6.
\281\ Id. at 4-5.
\282\ Id. at 5.
\283\ Id.
---------------------------------------------------------------------------
3. Commission Determination
132. With the clarifications noted below, we adopt the NOPR
proposal to apply the primary frequency response requirements adopted
herein to all newly interconnecting generating facilities as well as to
all existing large and small generating facilities that take any action
that requires the submission of a new interconnection request that
results in the filing of an executed or unexecuted interconnection
agreement on or after the effective date of this final action.\284\ In
response to SVP's request, we clarify that where the submission of a
new interconnection request by an existing generating facility results
in an executed or unexecuted interconnection agreement by that existing
generating facility, such event would be considered the triggering
event that would impose the requirements of this final action.
Accordingly, should an existing interconnection customer sign a new or
amended interconnection agreement for reformatting purposes only those
existing generating facilities would not be subject to the requirements
of this final action.\285\
---------------------------------------------------------------------------
\284\ NOPR, 157 FERC ] 61,122 at P 63.
\285\ Article 1 of the pro forma LGIA defines an interconnection
request as: ``an interconnection customer request, in the form of
Appendix 1 to the Standard Large Generator Interconnection
Procedures, in accordance with the Tariff, to interconnect a new
Generating Facility, or to increase the capacity of, or make a
Material Modification to the operating characteristics of, an
existing Generating Facility that is interconnected with the
Transmission Provider's Transmission System.'' Sections 30.9 and
30.10 of the pro forma LGIA provide that the LGIA and its appendices
may be amended by mutual agreement of the parties and do not state
that a new interconnection request must be submitted in order to do
so.
---------------------------------------------------------------------------
133. Bonneville suggests that the Commission should ``explore
defining what constitutes a `significant modification' '' to existing
generating facilities that would subject them to the primary frequency
response requirements adopted in this final action. It is unclear what
Bonneville means by ``significant modification.'' However, we note that
under the pro forma LGIP, a ``material modification'' \286\ to an
existing generating facility would result in an interconnection request
requiring a new interconnection agreement, thereby
[[Page 9656]]
subjecting the existing generating facility to the requirements adopted
in this final action.\287\ The Commission has not adopted a bright-line
definition of what constitutes a material modification; rather, that is
a fact-specific inquiry.\288\ Bonneville has not persuaded us that we
should adopt such a bright line now. Bonneville provides no information
regarding how many, if any, modification requests by existing
generating facilities would not be deemed material, and would therefore
not trigger the requirements of this final action, since the
interconnection customer would not be required to submit a new
interconnection request or execute a new interconnection agreement.
Accordingly, we are not persuaded by Bonneville of the need to include
a definition for the new term ``significant modification'' at this
time.
---------------------------------------------------------------------------
\286\ The pro forma LGIA defines a Material Modification as:
``those modifications that have a material impact on the cost or
timing of any Interconnection Request with a later queue priority
date.''
\287\ See pro forma LGIP Sec. 4.4.3.
\288\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 168.
---------------------------------------------------------------------------
134. Similarly, Xcel provides no support for its suggestion that a
significant number of new generating facilities, covered by a prior
interconnection agreement, may be built two or more years following the
effective date of this final action and therefore should be subject to
the primary frequency response requirements.\289\ Accordingly, we
decline to adopt Xcel's suggestion to require ``new generating
facilities that are interconnected two years or more after the
effective date of the Final Rule [to] also meet these requirements,
even if a new interconnection agreement is not required.'' \290\
---------------------------------------------------------------------------
\289\ Xcel Comments at 6.
\290\ Id. at 4.
---------------------------------------------------------------------------
135. Further, the Commission believes that ISO-RTO Council's
request that ``the Commission expand the application of the primary
frequency response requirements to both conforming and non-conforming
interconnection agreements resulting from new interconnection requests
by existing generators'' is unnecessary.\291\ ISO-RTO Council's concern
relates to the NOPR's use of the phrase ``filing of an executed or
unexecuted interconnection agreement.'' \292\ We note that if an
interconnection customer executes a new conforming interconnection
agreement for an existing generating facility as a result of a new
interconnection request, the agreement would not be filed at the
Commission but instead reported in Electric Quarterly Reports (EQRs).
However, a conforming new or amended LGIA or SGIA would need to conform
to the specific transmission provider's most recently revised pro forma
LGIA and pro forma SGIA, which would include the requirements of this
final action. The Commission clarifies that the final action is
intended to apply to all existing generating facilities that submit a
new interconnection request that results in an executed or unexecuted
interconnection agreement, regardless of whether that agreement is
filed at the Commission or merely reported in EQRs.
---------------------------------------------------------------------------
\291\ ISO-RTO Council Comments at 8.
\292\ See NOPR, 157 FERC ] 61,122 at PP 46, 54, 63.
---------------------------------------------------------------------------
G. Application to Existing Generating Facilities That Do Not Submit New
Interconnection Requests That Result in an Executed or Unexecuted
Interconnection Agreement
1. NOPR Proposal
136. In the NOPR, the Commission sought comment on the proposal to
apply the proposed reforms only to newly interconnecting generating
facilities. In particular, the Commission sought comment on whether
additional primary frequency response performance or capability
requirements for existing facilities are needed, and if so, whether the
Commission should impose those requirements by: (1) Directing the
development or modification of a reliability standard pursuant to
section 215(d)(5) of the FPA; or (2) acting pursuant to section 206 of
the FPA to require changes to the pro forma OATT.\293\
---------------------------------------------------------------------------
\293\ NOPR, 157 FERC ] 61,122 at PP 3, 57.
---------------------------------------------------------------------------
2. Comments
137. Most commenters oppose applying the proposed primary frequency
response requirements to existing generating facilities.\294\ Several
commenters argue that requiring existing generating facilities to
install and operate governors or equivalent controls would be overly
expensive and unnecessarily burdensome.\295\ Specifically, AWEA
contends that a retroactive primary frequency response requirement
would be particularly costly for older wind turbines with fixed blades
that cannot physically provide primary frequency response, newer wind
turbines that would still require substantial hardware and software
changes, and turbines from vendors that are out of business.\296\
Moreover, some commenters argue that a blanket requirement is
unnecessary given generally adequate levels of frequency response at
this time.\297\
---------------------------------------------------------------------------
\294\ PG&E, APPA et al., AWEA, NRECA, WIRAB, ELCON, Competitive
Suppliers, TVA, Public Interest Organizations, and Sunflower and
Mid-Kansas oppose expanding the applicability of the reforms to
existing generating facilities.
\295\ APPA et al. Comments at 7-8; NRECA Comments at 10; Public
Interest Organization Comments at 4; ELCON Comments at 5-6.
\296\ AWEA Comments at 4.
\297\ NRECA Comments at 10; WIRAB Comments at 10-12; Competitive
Suppliers Comments at 6.
---------------------------------------------------------------------------
138. NERC and the NYTOs contend that it is too soon after the
implementation of Reliability Standard BAL-003-1.1 to determine whether
it is necessary or appropriate to impose requirements for primary
frequency response on existing generating facilities.\298\
---------------------------------------------------------------------------
\298\ NERC Comments at 8; NYTOs Supplemental Comments at 3-4.
---------------------------------------------------------------------------
139. On the other hand, Bonneville and ISO-RTO Council support
reforms that would apply to existing generating facilities, suggesting
that the Commission direct NERC to develop a Reliability Standard for
frequency response. While Bonneville states that the cost to retrofit
existing generators may be prohibitive, it contends that a standard
similar to TRE's regional Reliability Standard BAL-001-TRE-01, which
requires generator owners/operators in the Texas region to set their
governors to meet performance requirements, would ensure both
capability and performance.\299\ ISO-RTO Council argues that the
development of a Reliability Standard will spread frequency response
requirements over many generating facilities in a non-discriminatory
manner and help facilitate compliance with Reliability Standard BAL-
003-1.1.\300\
---------------------------------------------------------------------------
\299\ Bonneville Comments at 3-4.
\300\ ISO-RTO Council Comments at 13.
---------------------------------------------------------------------------
140. Other commenters suggest that the Commission should wait to
apply the proposed reforms to existing generation facilities until
further research is completed. APPA et al. state that NERC's required
report on the availability of generating facilities to provide
frequency response,\301\ due in July 2018, will better inform the
Commission whether further action is needed on existing generating
facilities.\302\ WIRAB states that while it does not believe new or
modified Reliability Standards are currently needed, it recommends that
the Commission ``direct NERC and the Regional Entities to measure and
monitor frequency response, particularly governor response and
withdrawal, in Event Analysis and track resulting trends,'' \303\ and
develop guidelines and best practices that reflect regional
differences.\304\ WIRAB states
[[Page 9657]]
that NERC's Frequency Response Annual Analysis Report ``can easily be
expanded to track trends, model and analyze frequency response in each
of the interconnections over a 10-year time horizon, and to make
recommendations regarding current and future frequency response
needs.'' \305\ WIRAB states that if significant declines in frequency
response occur, such as decreasing frequency nadirs or continued
evidence of governor withdrawal, the Commission could then direct NERC
and the Regional Entities to develop or modify their mandatory
reliability standards and/or update NERC's Primary Frequency Control
Guideline to ensure frequency response is preserved.\306\
---------------------------------------------------------------------------
\301\ Order No. 794, 146 FERC ] 61,024 at P 3.
\302\ APPA et al. Comments at 3-4.
\303\ WIRAB Comments at 10.
\304\ Id. at 4.
\305\ Id. at 10.
\306\ Id. at 11.
---------------------------------------------------------------------------
141. In order to encourage regional flexibility and periodic
updating of the proposed maximum droop and deadband settings, WIRAB
recommends that the Commission direct NERC and the Regional Entities
``to monitor frequency response capability in each region, revisit and
revise NERC's droop and deadband setting guidelines as needed, and
generated best practices'' to encourage generating facilities to
``appropriately tighten regional droop and deadband settings as needed
to maintain system reliability.'' \307\ Further, WIRAB recommends that
the Commission periodically reexamine the specific droop and deadband
settings, which should not be viewed as a ``once-and-for-all
decision.'' \308\ In support of its position, WIRAB reminds the
Commission that NERC's Primary Frequency Control Guideline states that
tighter deadband settings of approximately 0.017 Hz can be
successfully implemented and encouraged efforts to lower deadband
settings to that level.\309\
---------------------------------------------------------------------------
\307\ Id. at 4.
\308\ Id.
\309\ Id. at 4-5.
---------------------------------------------------------------------------
142. Similarly, ISO-RTO Council requests the monitoring of the need
for existing generators to provide primary frequency response. ISO-RTO
Council acknowledges that NERC and the industry have already taken
steps to ensure sufficient primary frequency response, including the
development of Reliability Standard BAL-003-1.1, publishing an
operating guide for generating facilities, outreach to governor and
controls manufacturers, conducting webinars, as well as outreach to the
North American Generator Forum.\310\ ISO-RTO Council asserts that the
Commission should not delay the issuance of the final action by
requiring the development of a Reliability Standard for existing
generating facilities.\311\ Instead, it maintains such requirements
should be evaluated and, if necessary, proposed in a future
proceeding.\312\
---------------------------------------------------------------------------
\310\ ISO-RTO Council Comments at 11, n.23.
\311\ Id.
\312\ Id.
---------------------------------------------------------------------------
3. Commission Determination
143. We will not impose primary frequency response requirements on
existing generating facilities that do not submit new interconnection
requests that result in an executed or unexecuted interconnection
agreement. We conclude that applying the proposed requirements only to
newly interconnecting generating facilities will adequately address the
Commission's concerns regarding primary frequency response. We are
persuaded by commenters that requiring existing generating facilities
that have not submitted a new interconnection request to install and
operate governors or equivalent controls would be overly expensive and
unnecessarily burdensome.\313\ The record indicates that costs of
installing primary frequency response capability is minimal for newly
interconnecting generating facilities, and as such, we do not believe
that a mandate for compensation is needed at this time. However, the
record also indicates that the expense to some existing facilities may
be cost prohibitive,\314\ for example if retrofits are needed, and
accordingly we believe that applying the requirements to existing
generating facilities may be unduly burdensome.
---------------------------------------------------------------------------
\313\ APPA et al. Comments at 7-8; NRECA Comments at 10; Public
Interest Organization Comments at 4; ELCON Comments at 5-6.
\314\ See, e.g., Bonneville Comments at 3.
---------------------------------------------------------------------------
144. We agree that NERC, the Regional Entities, and other affected
industry stakeholders should continue to measure and monitor the impact
of Reliability Standard BAL-003-1.1 on generating facility frequency
response performance, and the amount and adequacy of primary frequency
response generally. We note that Order No. 794 required NERC to file in
July 2018 the results of a study on the availability of existing
generating facilities to provide primary frequency response.\315\ We
expect that NERC's July 2018 report will inform the Commission if
additional action is warranted regarding the need to impose additional
requirements on existing generating facilities.
---------------------------------------------------------------------------
\315\ Order No. 794, 146 FERC ] 61,024 at P 3.
---------------------------------------------------------------------------
145. NERC's July 2018 report will afford an opportunity for all
interested parties to consider WIRAB's recommendation to expand the
scope of NERC's Frequency Response Annual Analysis Report and/or State
of Reliability Report to ``track trends, model and analyze frequency
response in each of the [I]nterconnections over a 10-year time horizon,
and to make recommendations regarding current and future frequency
response needs.'' \316\ The July 2018 report may also provide insight
into whether NERC should consider tracking and reporting the resulting
trends of frequency response performance at the regional level (e.g.,
at the regional entity or balancing authority level), and if necessary,
develop guidelines and/or best practices that reflect regional
differences.\317\ This will allow the Commission to access future
standards directives, as necessary.
---------------------------------------------------------------------------
\316\ See WIRAB Comments at 10.
\317\ NERC already tracks frequency response performance at the
Interconnection-wide level in its annual State of Reliability
Report.
---------------------------------------------------------------------------
146. We also encourage NERC to review, and if necessary, update its
Primary Frequency Control Guideline as appropriate to reflect changes
in the generation resource mix, particularly as it pertains to the
technical attributes of non-synchronous generating facilities.
147. In addition, NERC and the Regional Entities should also
continue to monitor the operation and impact of the operating
requirements for droop, deadband, and sustained response adopted in
this final action, and recommend to the Commission any changes to those
settings (e.g., lower droop values or tighter deadband settings) in the
future that may become appropriate in light of changed circumstances.
H. Requests for Exemption or Special Accommodation
1. Combined Heat and Power Facilities
a. NOPR Proposal
148. In the NOPR, the Commission proposed to apply the primary
frequency response capability and operating requirements to all newly
interconnecting generating facilities, including CHP facilities.
b. Comments
149. ELCON and API contend that the special characteristics of
industrial CHP generating facilities warrant an exemption or special
accommodation from the proposed revisions to the pro forma LGIA and pro
forma SGIA.\318\
[[Page 9658]]
ELCON is concerned that, because of the unique connection between their
generation and industrial equipment, the mandatory nature of the new
primary frequency response requirements could adversely impact the
manufacturing processes of its member companies. ELCON asserts that the
generation equipment in CHP facilities ``which are part and parcel of
the load itself, cannot be treated as if they were conventional, stand-
alone generators, and forcing them to act as stand-alone generation
will compromise and potentially harm the manufacturing process by
interfering with the steam balance.'' \319\
---------------------------------------------------------------------------
\318\ ELCON Comments at 8-9; API Comments at 4-5. The Commission
notes that API states that CHP and cogeneration facilities are
interchangeable. See API Comments at 2. However, this final action
uses only the term ``CHP'' to avoid confusion with ``cogeneration
facility,'' which is a defined term under the Public Utility
Regulatory Policies Act of 1978. See 18 CFR 292.203(b) and 292.205
(2017).
\319\ ELCON Comments at 9.
---------------------------------------------------------------------------
150. In particular, ELCON explains that ``[g]eneration equipment
that is integrated with industrial process equipment is operated to
optimize the overall manufacturing process including the safe operation
of critical infrastructure'' and that ``[r]equiring all industrial
generation to provide primary frequency response without respect to the
operational needs of the manufacturing process may jeopardize the
reliability and safe operation of both.'' \320\
---------------------------------------------------------------------------
\320\ Id. at 8.
---------------------------------------------------------------------------
151. ELCON explains that there are a ``wide variety of
configurations and capacities in the universe of CHP generators that
are dedicated to an industrial process,'' with some CHP industrial
facilities designed to generate in excess of their load having ``the
flexibility to provide [primary frequency response] to the extent their
industrial process would not be impacted.'' \321\ ELCON also notes that
other CHP facilities are sized to match their industrial load, ``which
in reality means sized to the steam or thermal requirement of the host
manufacturing process.'' \322\ ELCON asserts that ``[s]uch facilities
cannot reasonably provide [primary frequency response] service without
compromising the efficiency, reliability and safe operation of the
manufacturing process.'' \323\
---------------------------------------------------------------------------
\321\ ELCON Supplemental Comments at 2-3.
\322\ Id.
\323\ Id.
---------------------------------------------------------------------------
152. For example, ELCON states that an increasing number of
manufacturers are installing turbines at their industrial facilities to
obtain lower emissions and other benefits \324\ that are susceptible to
a loss of combustion during certain types of frequency excursions.
ELCON explains that such events could have severe consequences,
including load curtailment and suspension, a manufacturing shutdown,
and execution of emergency procedures to de-pressure and stabilize
equipment.\325\ ELCON states that additional implications of such
events include ``the loss of production, possibly for an extended
period, additional maintenance and repair costs for equipment,
additional personnel costs, excess emissions during shutdown and
startup procedures, and although the shutdown process is designed to be
executed safely and effectively, some increased potential for safety,
health, and environmental consequences.'' \326\ During under-frequency
conditions, the provision of primary frequency response results in
increased MW output, which ELCON explains may result in a level of
steam production that exceeds the operating requirements of the
manufacturing process.\327\
---------------------------------------------------------------------------
\324\ Combustion turbines operating in ``lean-burn'' mode use a
higher air to fuel ratio (i.e., excess air is allowed into the
process) to reduce NOx emissions.
\325\ ELCON Supplemental Comments at 4.
\326\ Id. at 4-5.
\327\ Id. at 6. ELCON raises an additional concern that
mandating primary frequency response could discourage the
development of CHP facilities ``because of the added investment
cost, operational risk, efficiency loss and regulatory burden.'' Id.
at 9.
---------------------------------------------------------------------------
153. To address these concerns, ELCON states that ``the proposed
LGIA and SGIA language should be revised to explicitly exclude
imposition of mandatory primary frequency response obligations on
industrial CHP units and other similarly-situated forms of industrial
behind-the-meter generation.'' \328\ ELCON proposes the following new
language for the pro forma LGIA, Section 9.6.4.3 and pro forma SGIA,
Section 1.8.4.3 to specifically exempt ``industrial behind-the-meter
generation that is sized-to-load (i.e., the industrial load and the
generation are near-balanced in real-time operation and the generation
is controlled to maintain the unique thermal, chemical, or mechanical
output necessary for the operating requirement of its host industrial
facility).'' \329\ ELCON asserts, however, that an exemption from the
mandatory primary frequency response obligation still could allow
certain industrial processes that are capable of providing primary
frequency response to opt-in to such arrangements.\330\
---------------------------------------------------------------------------
\328\ Id. at 9.
\329\ Id. at 11.
\330\ Id.
---------------------------------------------------------------------------
154. API supports ELCON's exemption request, adding that CHP
facilities bring certain benefits such as high efficiency and lowered
emissions and that the proposal may present a barrier to entry for such
generating facilities.\331\ API contends that adjusting operating
levels for reasons outside of the manufacturing process, such as in
response to instructions of the balancing authority, ``risks a decline
in CHP efficiency and may introduce substantial risks to the
manufacturing process.'' \332\ Accordingly, API requests that the final
action exempt all CHP technologies from maintaining and operating
automatic turbine-generator governors as a condition of
interconnection, regardless of whether they are sized for load or
not.\333\
---------------------------------------------------------------------------
\331\ API Comments at 5.
\332\ Id.
\333\ Id. at 4.
---------------------------------------------------------------------------
c. Commission Determination
155. The Commission exempts newly interconnecting CHP facilities
that are sized to serve on-site load and have no material export
capability from the operating requirements of this final action.
However, considering the low costs associated with governor
installation, we will require all newly interconnecting CHP facilities,
including those sized-to-load, to install a governor or equivalent
control equipment capable of providing primary frequency response as a
condition of interconnection as proposed in the NOPR.\334\ We believe
that it is prudent to require newly interconnecting CHP facilities to
install primary frequency response capability now in the event that
there is an increased need in the future for primary frequency response
capability. Further, we adopt, with certain modifications, the
definition of ``sized-to-load'' contained in ELCON's proposed new
language for the pro forma LGIA and pro forma SGIA.\335\ In particular,
we define CHP facilities that are ``sized-to-load'' as those generating
facilities that are behind-the-meter generation that are sized-to-load
(i.e., the thermal load and the generation are near-balanced in real-
time operation and the generation is primarily controlled to maintain
the unique thermal, chemical, or mechanical output necessary for the
operating requirement of its host facility).\336\ We believe that
ELCON's request to limit the definition of ``sized-to-load'' only to
industrial CHP facilities is too narrow.
---------------------------------------------------------------------------
\334\ ELCON noted ``the low costs triggered by the NOPR's
limited applicability to only new generation facilities'' when
agreeing with the Commission's proposal not to mandate compensation.
ELCON Comments at 6.
\335\ See ELCON Supplemental Comments at 11.
\336\ Id.
---------------------------------------------------------------------------
156. We agree with ELCON and API that CHP facilities sized-to-load
present
[[Page 9659]]
unique concerns regarding the efficiency, reliability, and safe
operation of their industrial processes that warrant this exemption.
For example, ELCON notes that an increasing number of interconnection
customers with CHP facilities are using turbines susceptible to a loss
of combustion during certain types of frequency excursions, and that
such events could have severe consequences, including load curtailment
and suspension, a manufacturing shutdown, and execution of emergency
procedures to de-pressure and stabilize equipment.\337\ Additionally,
during under-frequency conditions, the provision of primary frequency
response results in increased MW output, which ELCON explains may
result in a level of steam production that exceeds the operating
requirements of the manufacturing process.\338\
---------------------------------------------------------------------------
\337\ ELCON Supplemental Comments at 4.
\338\ Id. at 6. ELCON raises an additional concern that
mandating primary frequency response could discourage the
development of CHP facilities ``because of the added investment
cost, operational risk, efficiency loss and regulatory burden.'' Id.
at 9.
---------------------------------------------------------------------------
2. Electric Storage Resources
a. NOPR Proposal
157. The NOPR proposed to apply the primary frequency response
capability and operating requirements to all new generating facilities,
including electric storage resources, without exception.
b. Comments
i. NOPR Comments
158. While most comments on the NOPR did not specifically request
an exemption for electric storage resources, some commenters suggest
changes to the proposed pro forma LGIA and pro forma SGIA provisions to
accommodate electric storage resources. In particular, ESA argues that
the proposed requirements disproportionately affect electric storage
resources in four ways.\339\ First, ESA states that the use of a
nameplate capacity basis for primary frequency response will require
storage to provide more frequent and greater magnitude of primary
frequency response service than traditional generating facilities.\340\
For example, ESA argues if a traditional generating facility with a
nameplate capacity of 100 MW has a minimum set point of 40 MW, the
primary frequency response service will be based on the 60 MW of
capacity above that minimum set point. However, ESA states that
electric storage has no minimum set point and is capable of operating
at the full range of its capacity for withdrawals and injections.\341\
---------------------------------------------------------------------------
\339\ ESA Comments at 3.
\340\ Id. at 3-4.
\341\ Id.
---------------------------------------------------------------------------
159. Second, ESA claims that whereas traditional generating
facilities start-up and shut-down as a part of normal operations and
are not required to provide primary frequency response while offline,
electric storage resources are, by contrast, ``always online'' even
when not charging or discharging.\342\ Therefore, ESA suggests that
electric storage resources will be available, on a more frequent basis,
to provide primary frequency response than other generating facilities
that go offline.\343\ Third, ESA states that different electric storage
technologies have different optimal depths of discharge, and exceeding
the optimal depth of discharge accelerates the degradation of the
facility and increases operations and maintenance costs. ESA asserts
that this scenario indicates the potential of the use of nameplate
capacity as the basis for primary frequency response to result in a
disproportionate impact on electric storage resources.\344\
---------------------------------------------------------------------------
\342\ Id. at 4.
\343\ Id.
\344\ Id. at 3-4.
---------------------------------------------------------------------------
160. Fourth, ESA notes that unlike traditional generating
facilities, electric storage is energy limited. Thus, ESA argues that
the requirement to sustain output in proposed section 9.6.4.2 of the
pro forma LGIA poses unique regulatory and financial exposure, such as
NERC violations and lost revenues in future intervals, especially when
a storage resource is at a low state of charge subsequent to the
provision of energy or ancillary services.\345\
---------------------------------------------------------------------------
\345\ Id. at 4.
---------------------------------------------------------------------------
161. ESA claims that, for these reasons, the proposal is unduly
discriminatory by potentially burdening storage, and recommends that
the NOPR proposal be modified to: (1) Establish a minimum set point for
primary frequency response service; and (2) include inadequate state of
charge as an explicit operational constraint exempting storage from
maintaining sustained output.\346\ Absent these requested changes, ESA
requests a complete exemption for electric storage resources.\347\
---------------------------------------------------------------------------
\346\ Id. at 4-5.
\347\ Id. at 5.
---------------------------------------------------------------------------
162. AES Companies request a complete exemption from the proposed
NOPR requirements for electric storage resources including but not
limited to battery storage devices providing one or more ancillary
services.\348\ AES Companies assert that the proposed requirement of a
maximum five percent droop setting, if imposed, would unnecessarily
limit the benefits that electric storage resources specifically
designed for primary frequency response can contribute to grid
stability.\349\ AES Companies also state that a five percent droop
setting ignores the majority of the primary frequency response capacity
that an electric storage resource was designed to deliver by directing
the resource to deliver only a fraction of its benefits.\350\ AES
Companies further argue for an exemption from the requirement to
dedicate a portion of the capacity of an electric storage resource for
the provision of primary frequency response.\351\ AES Companies state
that droop parameters should be specific to the technology, and that
requiring, for instance, a lithium ion battery to provide primary
frequency response at its full capacity would require a droop
approaching 0 percent.\352\
---------------------------------------------------------------------------
\348\ See AES Companies Comments at 17, 19 (i.e., specified
changes to the pro forma language).
\349\ Id. at 6. AES Companies contend that a five percent droop
will limit the amount of capacity that an electric storage resource
can dedicate to primary frequency response service.
\350\ Id.
\351\ Id. at 6. The Commission notes that in the NOPR, it did
not propose any mandatory headroom requirements.
\352\ AES Companies Comments at 7.
---------------------------------------------------------------------------
ii. Supplemental Comments
163. Supplemental commenters are split on whether electric storage
resources should be subject to the operating requirements proposed in
the NOPR. Tri-State, ISO-RTO Council, Berkshire, NERC, and WIRAB
support applying the proposed requirements to electric storage
resources. SoCal Edison opposes the proposed operating requirements,
but explains that if the Commission adopts the proposal, it should be
applicable to all newly interconnecting generating facilities on a
technology neutral basis so that such requirements will be implemented
in a non-discriminatory fashion.\353\
---------------------------------------------------------------------------
\353\ SoCal Edison Supplemental Comments at 2.
---------------------------------------------------------------------------
164. However, Sunrun, AES Companies, and CESA comment that electric
storage resources would bear a disproportionate impact compared to
other resources due to the proposed droop and sustained response
requirements, and therefore request an exemption or an accommodation
from the proposed requirements. Several other commenters reiterate
their initial NOPR comments that operating requirements for primary
frequency response should not be included in the pro forma LGIA and pro
forma SGIA, stating that a market-based approach to
[[Page 9660]]
primary frequency response, or regional flexibility in facilitating the
provision of primary frequency response (e.g., allowing balancing
authorities to determine which generating facilities should supply
primary frequency response) would lead to more efficient and cost
effective outcomes.\354\
---------------------------------------------------------------------------
\354\ See, e.g., EEI Comments at 4-5.
---------------------------------------------------------------------------
165. A number of commenters reference either technical or economic
challenges that would be unique to electric storage resources under the
proposed requirements. Sunrun, ESA, and CESA state that electric
storage resources have a finite lifecycle, and that compliance with the
proposed operating requirements for timely and sustained response may
limit the lifetime of an electric storage resource.\355\ These
commenters also assert that different electric storage technologies
will have different depths of discharge and may face different
challenges under the proposed operating requirements.
---------------------------------------------------------------------------
\355\ Sunrun Supplemental Comments at 2; ESA Supplemental
Comments at 4; CESA Supplemental Comments at 11.
---------------------------------------------------------------------------
166. ESA argues that the proposed droop and sustained response
requirements would impose adverse conditions on electric storage
resources because they would bear a disproportionate impact on the
provision of primary frequency response capability compared to other
generating facilities. In particular, ESA asserts that because electric
storage resources are energy-limited, it is inappropriate to require
electric storage resources to provide sustained response because doing
so would constrain electric storage resources from effectively managing
their fuel supply (i.e., state of charge), potentially reducing their
ability to fulfill service obligations and creating an effective
headroom requirement.\356\
---------------------------------------------------------------------------
\356\ ESA Supplemental Comments at 3.
---------------------------------------------------------------------------
167. ESA restates its NOPR comment that droop is calculated as a
percent of nameplate capacity above a minimum set point, and because
electric storage resources lack such a set point, storage resources
will be required to provide proportionally greater primary frequency
response service.\357\ In addition, ESA states that if an electric
storage resource is charging when called upon to provide primary
frequency response, the switch to discharging means that the electric
storage resource will provide both the injected energy and the removal
of an effective ``load,'' creating a response significantly greater
than contemplated in the proposed droop settings.\358\ However, EPRI
states that this concern can be mitigated if the Commission makes
certain clarifications in the final action. In particular, EPRI states
that the NOPR requirement setting the droop curve at no more than five
percent, based on nameplate capacity, can be assumed to refer to a
slope equating to a five percent change in frequency causing a change
in the full discharge capacity (not discharge capacity plus charge
capacity) of the electric storage resource.\359\ Both AES Companies and
ESA comment that the proposed deadband and timely response requirements
do not pose challenges or adverse operational impacts for most electric
storage resources.\360\
---------------------------------------------------------------------------
\357\ Id. at 4.
\358\ Id.
\359\ EPRI Supplemental Comments at 6.
\360\ AES Companies Supplemental Comments at 23; ESA
Supplemental Comments at 6.
---------------------------------------------------------------------------
168. Additionally, ESA claims that since electric storage resources
are always ``online,'' as opposed to generating facilities that start-
up and shut-down (i.e., go offline), electric storage resources would
be available to provide primary frequency response on a more frequent
basis, and would therefore be expected to provide more primary
frequency response service than generating facilities that go
offline.\361\ On the other hand, APS states that while it acknowledges
that electric storage resources could provide more primary frequency
response than other resources, such provision will be limited by the
obligations and operational characteristics and design of such
resources, similar to all other resource types. In particular, if there
is to be a minimum state of charge below which electric storage
resources would not have to provide primary frequency response, these
resources may not be providing primary frequency response of greater
magnitude than other resources.\362\
---------------------------------------------------------------------------
\361\ ESA Supplemental Comments at 7.
\362\ APS Supplemental Comments at 6.
---------------------------------------------------------------------------
169. Several commenters assert that there is little substantive
difference between the operating constraints faced by electric storage
resources and the operational characteristics that limit the capacity
of other types of generating facilities to provide primary frequency
response.\363\ For example, NERC asserts that ``run-of-river hydro
units may have insufficient river flow, thermal units may have
discharge temperature limitations on cooling water, gas turbines may
need to be derated during the summer, pumped storage may not have yet
refilled storage reservoirs, and units may be in the middle of coming
on or going off-line.'' \364\ NERC states that while several types of
generating facilities have technical limitations that may inhibit their
ability to provide primary frequency response under certain
circumstances, these operating constraints should not preclude any
generating facility from maintaining primary frequency response
capability.\365\ A number of supplemental commenters state that any
determination regarding accommodations to mitigate such operational
constraints, including, for example, the threshold limit below which an
electric storage resource should be required to provide primary
frequency response or allowed to disconnect from the grid during low
frequency events, must be made on a case-by-case basis and can be done
during the interconnection process.\366\ Further, APS comments that the
operational wear and tear on electric storage resources and its impact
on the overall life expectancy of an electric resource is not
significantly different than the potential impact of wear and tear on
other generating facilities.\367\
---------------------------------------------------------------------------
\363\ See, e.g., APS Supplemental Comments at 4; NERC
Supplemental Comments at 5, stating that operating constraints
should not preclude any new generating facility from maintaining
primary frequency response capability.
\364\ NERC Supplemental Comments at 5.
\365\ Id.
\366\ See, e.g., APS Supplemental Comments at 5, 7; EPRI
Supplemental Comments at 12-13; NRECA Supplemental Comments at 3;
NERC Supplemental Comments at 5, stating that interconnection
customers should evaluate any ``technical limitations on a unit-by-
unit basis and coordinate with their NERC Balancing Authority and
Interconnection Agreement Transmission Provider/Transmission Owner,
as appropriate.''
\367\ APS Supplemental Comments at 7.
---------------------------------------------------------------------------
170. ISO-RTO Council also believes that possible accommodations or
exemptions for electric storage resources and small generators are
unwarranted, stating that such measures could allow such resources to
avoid solving the very problem to which such resources contribute and
the NOPR rules were intended to address.\368\ ISO-RTO Council asserts
that the proposed requirements are consistent with the recommendations
and guidelines contained in NERC's Primary Frequency Control Guideline,
and are similar to the current requirements of PJM, ISO-NE, and CAISO
for electric storage resources and/or small generators to install,
maintain and operate primary frequency response related equipment as a
condition of interconnection ``that have not required exemptions for
either electric storage resources or small generators.'' \369\ ISO-RTO
Council
[[Page 9661]]
further notes that primary frequency response capability requirements
that already exist in ``areas with substantial penetration of renewable
resources'' in the European Union have not had ``negative impacts.''
\370\
---------------------------------------------------------------------------
\368\ ISO-RTO Council Supplemental Comments at 2.
\369\ Id. at 3.
\370\ Id. at 4 (citing ENTSO-E requirements for Generators,
Chapter 1, Article 13).
---------------------------------------------------------------------------
171. EPRI states that the unique characteristics of electric
storage resources should not directly affect the current requirements
for droop settings.\371\ Specifically, EPRI comments that there is a
limited amount of additional power required (2 percent of nameplate or
less for a 0.1 Hz frequency deviation) and a limited amount of time it
must be sustained (generally five minutes or less, maximum about seven
minutes).\372\ EPRI concludes that the energy required to provide
sustained frequency response is very small in relation to the energy
that the electric storage resource would be providing otherwise.\373\
---------------------------------------------------------------------------
\371\ EPRI Supplemental Comments at 4.
\372\ Id.
\373\ Id.
---------------------------------------------------------------------------
172. While ESA supports an exemption for electric storage
resources, it suggests several accommodations to the proposed
requirements to mitigate the potentially adverse impact of the proposed
requirements on electric storage resources. ESA asserts that electric
storage resources should have a means to effectively ``go offline,''
similar to generating facilities on shut down, and that the language
``whenever the Large Generating Facility is operated in parallel with
the Transmission System'' in Section 9.6.2.1 should be interpreted to
mean providing services to the grid and should exclude simply being
idle.\374\ WIRAB adds that it would not be just and reasonable to
require an electric storage resource to enable primary frequency
response while in standby mode when other generating facilities are not
subject to a similar requirement.\375\
---------------------------------------------------------------------------
\374\ ESA Supplemental Comments at 8.
\375\ WIRAB Supplemental Comments at 6.
---------------------------------------------------------------------------
173. ESA also suggests that electric storage resources should be
exempt from requirements for providing sustained primary frequency
response when such a resource does not have enough energy stored to
provide sustained frequency response at required capacity when a
frequency deviation occurs (i.e., inadequate state of charge).\376\ ESA
states that this exemption for ``inadequate state of charge'' should be
included along with the allowances for ambient temperature limitations,
outages of mechanical equipment, and regulatory requirements in the
proposed tariff language of Section 9.6.4.2. WIRAB agrees that the
concept of energy limitation should be included as an exemption to
sustained response in proposed Section 9.6.4.2 of the pro forma LGIA
and 1.8.4.2 of the pro forma SGIA, but clarifies that this exemption
should not apply only to electric storage resources because other
generating facilities also face energy limitations.\377\
---------------------------------------------------------------------------
\376\ ESA Supplemental Comments at 10.
\377\ WIRAB Supplemental Comments at 5.
---------------------------------------------------------------------------
174. ESA states that, in lieu of other mechanisms to accommodate
electric storage resources, operators of electric storage resources
could specify an operating range outside of which electric storage
resources would not be required to provide and/or sustain primary
frequency response.\378\ Doing so, according to ESA, would prevent the
excessive wear and tear impacts on electric storage resources, as well
as potentially mitigate inadequate state of charge for sustained
response.\379\ However, ESA states that even with this approach to
mitigate adverse impacts of primary frequency response requirements,
electric storage resources would continue to face constraints on state
of charge management and a reduction in capability to provide other
energy and ancillary services, primarily as a result of the
unpredictable nature of abnormal frequency deviations.\380\ APS
comments that establishing a minimum set point or an operating range
are both workable solutions, and argues that the Commission should
allow flexibility in determining the approach on a case-by-case
basis.\381\ APS states that an operating range could be established
through collaboration and evaluation during the interconnection process
and included in the interconnection agreement.\382\ EPRI comments that
a static operating range could lead to inefficiencies.\383\ AES
Companies does not support the use of an operating range.\384\
---------------------------------------------------------------------------
\378\ ESA Supplemental Comments at 12-13.
\379\ Id. at 13.
\380\ Id.
\381\ APS Supplemental Comments at 9.
\382\ Id. at 8-9.
\383\ EPRI Supplemental Comments at 15.
\384\ AES Companies Supplemental Comments at 38.
---------------------------------------------------------------------------
175. SDG&E believes that markets for primary frequency response
have the potential to eliminate nearly all the issues addressed by the
questions in the Commission's Request for Supplemental Comments.\385\
Berkshire recommends that the Commission acknowledge in the final
action that electric storage resources are not always utilized as
generation or accounted for as generation assets, and that the
Commission consider holding a technical conference to discuss
alternative applications for electric storage resources apart from
providing primary frequency response within a prescribed
bandwidth.\386\
---------------------------------------------------------------------------
\385\ SDG&E Supplemental Comments at 3-4
\386\ Berkshire Supplemental Comments at 2-3.
---------------------------------------------------------------------------
c. Commission Determination
176. In consideration of the unique physical and operational
characteristics of electric storage resources, we will require
transmission providers to include in their pro forma LGIA and pro forma
SGIA specific accommodations for electric storage resources and place
limitations on when electric storage resources will be required to
provide primary frequency response consistent with the conditions set
forth in Sections 9.6.4, 9.6.4.1, 9.6.4.2, 9.6.4.3, and 9.6.4.4 of the
pro forma LGIA and Sections 1.8.4, 1.8.4.1, 1.8.4.2, 1.8.4.3, and
1.8.4.4 of the pro forma SGIA, as applicable.
177. Specifically, as discussed in further detail below, this
includes the identification of an operating range within which electric
storage resources will be required to provide primary frequency
response, the identification of particular operating circumstances when
electric storage resources will not be required to provide primary
frequency response, and the inclusion of energy limitations in the list
of exemptions from the requirement to provide primary frequency
response.
178. We disagree with SoCal Edison, ISO-RTO Council, and WIRAB that
suggest electric storage resources should be subject to the same
requirements for primary frequency response as all other
resources.\387\ We find that the provision of primary frequency
response in accordance with the requirements of this final action may
present challenges for some electric storage resources. Specifically,
we are persuaded by ESA's comments that requiring an electric storage
resource to sustain its output without any consideration for whether
the electric storage resource has sufficient state of charge could
result in depths of discharge that could accelerate the degradation of
an electric storage resource. However, while we agree that electric
storage resources could experience disproportionate harm from the
proposed requirements under some circumstances, we are also persuaded
by EPRI's suggestion that those harms would be modest and can be
mitigated with certain
[[Page 9662]]
accommodations.\388\ In particular, EPRI notes that ``the energy
required to provide sustained primary frequency response is very small
in relation to the energy that the electric storage resource would be
providing otherwise due to provision of energy or other ancillary
services such that the risk of running into state of charge limits
would already be known and not likely impacted by provision of primary
frequency response by itself.'' \389\
---------------------------------------------------------------------------
\387\ ISO-RTO Supplemental Comments at 4-5; SoCal Edison
Supplemental Comments at 2; WIRAB Supplemental Comments at 3.
\388\ ``If an electric storage resource is not providing any
online service, it should not be required to provide primary
frequency response to align with the rules designated in the NOPR.''
EPRI Supplemental Comments at 8; ``Resources claiming artificial
minimum set points during operational time frames that they would
not provide primary frequency response during over-frequency events
can be managed on a case-by-case basis, if sufficient primary
frequency response capability is otherwise available.'' EPRI
Supplemental Comments at 10; ``The [operating] range should be
provided if there are any ``rough zones'' for any technologies where
primary frequency response is not controllable, not possible, or
would lead to extraordinary damage or wear-and-tear costs.'' EPRI
Supplemental Comments at 15.
\389\ EPRI Supplemental Comments at 4.
---------------------------------------------------------------------------
179. We are persuaded by ESA's comment that allowing operators of
electric storage resources to specify an operating range ``would
prevent the excessive wear and tear impacts on electric storage as well
as potentially mitigate inadequate state of charge for sustained
response.'' \390\ Therefore, while acknowledging the limited degree of
the amount of energy that will be required to provide sustained
response,\391\ we find that, on balance, limiting the circumstances
under which electric storage resources are required to provide primary
frequency response will adequately alleviate the potential for
excessive wear and tear that may have otherwise been experienced by
electric storage resources.
---------------------------------------------------------------------------
\390\ See ESA Supplemental Comments at 12-13.
\391\ See EPRI Supplemental Comments at 4, stating that ``the
energy required to provide sustained primary frequency response is
very small in relation to the energy that the electric storage
resource would be providing otherwise due to provision of energy or
other ancillary services.''
---------------------------------------------------------------------------
180. Specifically, we will require electric storage resources to
identify in their interconnection request an operating range for the
basis of the provision of primary frequency response. This operating
range will represent the minimum and maximum states of charge between
which an electric storage resource will be required to provide primary
frequency response. The operating range for each electric storage
resource will need to be agreed to by the interconnection customer and
transmission provider, in consultation with the applicable balancing
authority or any other relevant parties as appropriate, consider the
system needs for primary frequency response, and the physical
limitations of the electric storage resource as identified by the
developer and any relevant manufacturer specifications, and be
established in Appendix C of the pro forma LGIA (``Interconnection
Details'') or Attachment 5 of the pro forma SGIA (``Additional
Operating Requirements for the Transmission Provider's Transmission
System and Affected Systems Needed to Support the Interconnection
Customer's Needs''). We find that this operating range addresses
concerns regarding excessive wear and tear on electric storage
resources, mitigates the concerns about inadequate state of charge, and
effectively allows electric storage resources to identify a minimum and
maximum set point below and above which they will not be obligated to
provide primary frequency response comparable to synchronous generation
as suggested by ESA.\392\
---------------------------------------------------------------------------
\392\ See ESA Supplemental Comments at 12-13.
---------------------------------------------------------------------------
181. However, we do not agree with ESA that electric storage
resources should not be required to specify the details of an
inadequate state of charge parameter in their interconnection
agreements.\393\ We find that requiring an electric storage resource to
identify the states of charge at which it is unable to inject or
receive additional energy to provide primary frequency response is
necessary to mitigate the adverse impacts on electric storage resources
while still requiring them to provide this essential reliability
service when they are technically capable to do so. While we believe
that the interconnection customer will have the best information
regarding the physical capabilities of the electric storage resource
and any limitations that should be placed on its operations due to
manufacturer specifications, we also believe that the transmission
provider will have the best information with respect to: (1) The
expected magnitude of frequency deviations; (2) the expected duration
that system frequency will remain outside of the deadband parameter;
and (3) the expected incidence of frequency deviations outside of the
deadband parameter. This information from the transmission provider is
necessary for the interconnection customer to calculate the anticipated
obligations to provide primary frequency response for an electric
storage resource in terms of the energy requirements for individual
incidents, as well as increased electricity throughput (i.e., cycling)
over the life of the electric storage resource. We note that both the
physical limitations of the electric storage resource, as identified by
the interconnection customer, and the expected primary frequency
response system requirements, as identified by the transmission
provider, may be necessary to determine the appropriate operating range
for an electric storage resource. Therefore, we find that it is
necessary to provide the interconnection customer with the ability to
propose an operating range with its initial interconnection request,
but also allow the transmission provider and/or balancing authority to
consider the system needs for primary frequency response prior to
reaching an agreement on the final operating range among the parties in
a LGIA or SGIA. We also find that the transmission providers must treat
electric storage resources in a not unduly discriminatory or
preferential manner when determining the appropriate operating range.
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\393\ See ESA Supplemental Comments at 11.
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182. Because the requirements for primary frequency response may
change over time, the Commission is persuaded by commenters that it is
appropriate to provide transmission providers with flexibility to
determine whether the operating ranges established in the
interconnection agreements for electric storage resources are static or
dynamic values.\394\ We understand that system conditions and
contingency planning can change, which may alter the anticipated
incidence, magnitude, and duration of frequency deviations.
Additionally, the capabilities of electric storage resources to provide
primary frequency response may change due to degradation, repowering,
or changes in service obligations, and these may also need to be
considered when revisiting a dynamic operating range.\395\ If a
transmission provider decides to implement a dynamic operating range
for an electric storage resource to provide primary frequency response,
it must also determine how frequently the operating range will be
reevaluated and the factors that may be considered when reevaluating it
either on a case-by-case basis in Appendix C of the pro forma LGIA and
Attachment 5 of the pro forma SGIA, or as a standard approach filed in
compliance with this final action. To the extent that the
interconnection customer and the transmission provider
[[Page 9663]]
cannot agree on these issues, the interconnection customer has the
right to request the filing of an unexecuted interconnection agreement
to seek Commission resolution.
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\394\ See, e.g., APS Supplemental Comments at 8; EPRI
Supplemental Comments at 15; ESA Supplemental Comments at 13.
\395\ A dynamic operating range will allow the minimum and
maximum state of charge values that define the operating range to
change over time based on changing system needs and/or electric
storage resource capabilities.
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183. Additionally, we agree with comments that suggest certain
electric storage technologies are always online and capable of
providing primary frequency response, and that without any
accommodation, those resources could be required to provide sustained
primary frequency response more frequently than other generating
facilities that start up and shut down (i.e., go offline).\396\
Therefore, we find that it is appropriate to place limitations on when
electric storage resources are required to provide primary frequency
response. In particular, we agree with EPRI that ``[if] an electric
storage resource is not providing any online service, it should not be
required to provide primary frequency response.'' \397\ To require an
electric storage resource to provide a service under conditions that
other generating facilities are not required to provide it would raise
discrimination concerns. Therefore, we revise the pro forma LGIA and
pro forma SGIA to make clear that electric storage resources will only
be required to provide primary frequency response when they are online
and are dispatched to inject electricity to the grid and/or dispatched
to receive electricity from the grid. We clarify that the requirement
to provide primary frequency response will exclude situations when an
electric storage resource is not dispatched to inject electricity to
the grid and/or dispatched to receive electricity from the grid.
---------------------------------------------------------------------------
\396\ See ESA Supplemental Comments at 7.
\397\ See EPRI Supplemental Comments at 8. EPRI states that the
determination of a generating facility being online is ``it being
connected to the grid and providing online services (energy or
online ancillary services).''
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184. We also agree with WIRAB that electric storage resources and
some other resources could face physical limitations that would make
them unable to provide primary frequency response, and believe that
accommodations for such limitations are appropriate.\398\ While the
previously discussed accommodations for electric storage resources are
intended to limit adverse impacts of the primary frequency response
requirements on them, we find that providing a specific exemption for
physical energy limitations will not only further ensure that electric
storage resources are not required to provide primary frequency
response when they are physically unable to do so, but it will also
prevent other resources that experience similar physical limitations
from being required to provide the service when they are not able to.
Conditions under which a resource is physically unable to provide
primary frequency response could, for example, include an inability for
an electric storage resource to increase its output because it does not
have any stored energy (i.e., its state of charge is equal to zero), or
an inability for a wind or solar generating facility to increase output
because there is not sufficient wind or solar energy to allow an
increase in MW output.
---------------------------------------------------------------------------
\398\ See WIRAB Supplemental Comments at 4.
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185. Moreover, we find that including this exemption in the pro
forma LGIA and pro forma SGIA is consistent with our finding that it is
not necessary to establish a headroom requirement for primary frequency
response. Because we are not requiring newly interconnecting generating
facilities to maintain headroom to provide primary frequency response,
we find that it is unjust and unreasonable to require the provision of
primary frequency response from generating facilities that are
physically unable to provide the service. Accordingly, we clarify that
all generating facilities subject to this final action will be exempt
from the timely and sustained frequency response requirements if they
experience a physical energy limitation that would prevent them from
fulfilling their obligations that would have otherwise been required
under the parameters set forth in this final action. To implement this
requirement, we modify the list of exemptions in Section 9.6.4.2
(Timely and Sustained Response) of the pro forma LGIA and Section
1.8.4.2 (Timely and Sustained Response) of the pro forma SGIA to
include the term ``physical energy limitation.'' We define ``physical
energy limitation'' to mean the circumstance when a resource would not
have the physical ability, due to insufficient remaining charge for an
electric storage resource or insufficient remaining fuel for a
generating facility to satisfy its timely and sustained primary
frequency response service obligation, as dictated by the magnitude of
the frequency deviation and the droop parameter of the governor or
equivalent controls. However, we also find that when a generating
facility experiences a physical energy limitation, then the
interconnection customer must be able to demonstrate to the
transmission provider, and to the extent applicable, the relevant
balancing authority, that such a physical energy limitation existed
before or during an abnormal frequency deviation outside of the
deadband parameter.
186. We find that ESA's comments that suggest a minimum set point
should be used in the determination of the droop response are
misplaced. A generating facility's minimum set point is not used in the
calculation of the MW droop response. We clarify that for all
generating facilities, the calculation of the MW droop response is
based on a generating facility's nameplate capacity (i.e., for a five
percent droop curve, a generating facility would be expected to
increase its output by 100 percent of its nameplate capacity for a five
percent change in frequency). While it is true in theory that an
electric storage resource may have a greater operating range over which
to provide primary frequency response, from a practical standpoint the
droop parameter limits the percentage of nameplate capacity that a
generating facility will provide in response to abnormal frequency
deviations.\399\
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\399\ For example, as pointed out by EPRI, ``[a] [five percent]
droop setting and 36mHz deadband equates to an individual resource
having a frequency response of about [two percent of] nameplate
capacity per tenth of a Hz at a tenth of a Hz frequency deviation.''
EPRI Supplemental Comments at 7.
---------------------------------------------------------------------------
187. ESA contends that ``[i]f a storage resource is charging when
called to provide [primary frequency response], the switch to
discharging means that the storage [resource] will provide both the
injected energy and the removal of an effective `load,' creating a
response significantly greater than contemplated in the proposed droop
settings.'' \400\ To address ESA's concern, we will require electric
storage resources that are being dispatched to charge at the time of an
abnormal frequency deviation to increase (for over-frequency
deviations) or decrease (for under-frequency deviations) the rate at
which they are charging according to the droop parameter to satisfy the
timely and sustained primary frequency response requirement. For
example, if an electric storage resource is charging at two MW prior to
an abnormal under-frequency deviation, and the calculated response per
the droop parameter is to increase real-power output by one MW, the
electric storage resource could satisfy its obligation by reducing its
consumption by one MW (instead of completely reducing its consumption
by the full two MW and then discharging at one MW, which would result
in a net of three MW provided as primary frequency response). Further,
if an electric storage resource is capable of switching from charging
to discharging, or vice versa, within the time period that the primary
frequency response is
[[Page 9664]]
needed the resource should do so if necessary to meet its calculated
response. For example, if an electric storage resource is charging at
one MW prior to an abnormal under-frequency deviation, and the
calculated response per the droop parameter is to increase real-power
output by three MW, the electric storage resource could satisfy its
obligation by switching from charging at one MW to discharging at two
MW. We clarify that electric storage resources would not be required to
change from charging to discharging, or vice versa, if they are not
technically capable of making the transition during the period in which
the primary frequency response is needed.
---------------------------------------------------------------------------
\400\ ESA Supplemental Comments at 3-4.
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188. Regarding AES Companies' contention that a five percent droop
setting ignores the majority of the primary frequency response capacity
that an electric storage resource was designed to deliver,\401\ we note
that, as stated in the NOPR, the requirements adopted in this final
action are minimum requirements; therefore, if a new generating or
electric storage facility elects, in coordination with its transmission
provider and/or balancing authority, to operate in a more responsive
mode by using lower droop or tighter deadband settings, nothing in
these requirements would prohibit it from doing so.\402\
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\401\ AES Companies Comments at 6.
\402\ NOPR, 157 FERC ] 61,122 at P 48.
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189. Finally, we are not persuaded by Berkshire that a technical
conference is needed at this time because there is sufficient evidence
in the record to make a finding on this issue, as discussed in this
final action.
3. Distributed Energy Resources
a. NOPR Proposal
190. In the NOPR, the Commission proposed to apply the primary
frequency response capability and operating requirements to all newly
interconnecting generating facilities interconnecting through an LGIA
or SGIA.\403\
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\403\ Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 7, order
on reh 'g, Order No. 2006-A, FERC Stats. & Regs. ] 31,196, order on
clarification, Order No. 2006-B, FERC Stats. & Regs. ] 31,221.
---------------------------------------------------------------------------
b. Comments
191. Several commenters assert that the final action should include
special considerations for generating facilities connecting at the
distribution level. Public Interest Organizations state that, in the
NOI, SolarCity Corporation raised concerns that already-installed
behind-the-meter generation and DERs could become subject to the pro
forma SGIA should those DERs opt to participate in wholesale energy
markets.\404\ Public Interest Organizations request that the Commission
clarify the circumstances in which DER participation in wholesale
energy markets would trigger requirements in the SGIA because
``[u]nless warranted by a significant shortfall of primary frequency
response service, requiring the retrofit of existing generators for
primary frequency response capability under such circumstances would
not be cost-effective.'' \405\ TVA states that exceptions to the
primary frequency response requirements could reasonably be justified
for generating facilities interconnected only through lower voltage
distribution systems.\406\
---------------------------------------------------------------------------
\404\ Public Interest Organizations Comments at 3.
\405\ Id. at 3-4.
\406\ TVA Comments at 4.
---------------------------------------------------------------------------
192. Xcel argues that dynamic frequency response at the
distribution level can interfere with anti-islanding \407\ protection
methods, and that, unlike transmission-connected generation, generating
facilities connected to the distribution system must meet the anti-
islanding requirements of the Institute of Electrical and Electronics
Engineers (IEEE) Standards to protect the distribution system.\408\
Xcel explains that the IEEE anti-islanding standards may require that
the primary frequency response of the facility be restricted or that
suitable mitigation measures be installed.\409\ Accordingly, Xcel
asserts that the pro forma SGIA should require that the distribution
system operator be notified of the primary frequency response
capabilities of a generating facility to be connected to the
distribution system, and that the distribution system operator must
have the ability to place limitations on the primary frequency response
of the generating facility if such limitations are required to ensure
system reliability and power quality.\410\
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\407\ Islanding refers to the condition in which a DER continues
to power a location even though electrical grid power from the
electric utility is no longer present. Unintentional islanding can
pose a hazard to utility personnel and customer equipment, and it
may prevent automatic re-connection of devices. The currently
effective version of IEEE-1547 standard requires that for an
unintentional island in which the DER energizes a portion of the
distribution system, the DER shall detect the island and cease to
energize the system within two seconds of the formation of an
island.
\408\ Xcel Comments at 9; IEEE Standard 1547-2003,
Interconnecting Distributed Resources with Electric Power Systems
and IEEE Standard 1547a-2014, Interconnecting Distributed Resources
with Electric Power Systems Amendment 1.
\409\ Xcel Comments at 9.
\410\ Id.
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c. Commission Determination
193. The requirements of this final action will apply to newly
interconnecting DERs that execute, or request the unexecuted filing of,
an LGIA or SGIA on or after the effective date of this final action. We
find Public Interest Organizations' request that the Commission clarify
the circumstances in which DER participation in wholesale energy
markets would trigger requirements in the pro forma SGIA to be outside
the scope of this proceeding.\411\
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\411\ CAISO, ISO-NE, MISO, NYISO, PJM, and SPP all have programs
that allow demand response and/or certain demand-side resources to
aggregate and participate in wholesale markets. The CAISO model
requires a prospective DER aggregator to execute a Distributed
Energy Resource Provider Agreement to accept and abide by the terms
of the CAISO Tariff, but does not require the DER aggregator nor the
aggregated DERs to execute an SGIA. See Cal. Indep. Sys. Operator
Corp., 155 FERC ] 61,229, at P 1 (2016) (conditionally accepting
tariff provisions to facilitate participation of aggregations of
distribution-connected or distributed energy resources in CAISO's
energy and ancillary service markets).
---------------------------------------------------------------------------
194. Xcel is concerned that dynamic frequency response at the
distribution level can interfere with anti-islanding protection
methods. The sustained response provisions adopted herein would require
a generating facility, only to the extent that it is allowed to remain
online and ride through a disturbance and has operating capability in
the direction needed to counteract the frequency deviation, to provide
and sustain its response.
195. The Commission in Order No. 828 provided flexibility to
address anti-islanding concerns by finding that, if a transmission
provider believes a particular facility has a higher risk of
unintentional islanding due to specific conditions at that facility,
the transmission provider may coordinate with the small generating
facility to set ride through settings appropriate for those conditions,
in accordance with Good Utility Practice and the appropriate technical
standards.\412\ For those facilities with a lower risk of forming an
unintentional island, the Commission found that they can be held to a
longer ride through requirement.\413\
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\412\ See Order No. 828, 156 FERC ] 61,062 at P 28.
\413\ Id.
---------------------------------------------------------------------------
196. We clarify that the sustained response provisions in the
revisions to the pro forma LGIA and pro forma SGIA apply only when a
generating facility is allowed to ride through, and do not supersede a
generating facility's ride through settings, or require an
interconnection customer to override anti-islanding protection or any
protective relaying that has been set to
[[Page 9665]]
disconnect the generating facility during certain abnormal system
conditions. Further, we clarify that for those abnormal system
conditions in which a generating facility is not tripped offline by
anti-islanding or protective relays and remains connected, to the
extent it has the necessary MW operating capability in the appropriate
direction to correct the frequency deviation, it would be expected to
provide and sustain primary frequency response.
197. Accordingly, the obligations imposed for primary frequency
response apply only to generating facilities allowed to ride through
and, because the ride through settings will be coordinated between the
interconnection customer and the transmission provider, we believe this
should adequately address Xcel's anti-islanding concerns.
4. Nuclear Generating Facilities
a. NOPR Proposal
198. In the NOPR, the Commission proposed to exempt generating
facilities regulated by the NRC due to their unique operating
characteristics and regulatory requirements.
b. Comments
199. Several commenters support the exemption for nuclear
generating facilities.\414\ EEI and the MISO TOs agree with the
proposed exemption, explaining that nuclear units are restricted by
their NRC operating licenses on the amount of primary frequency
response, if any, they can provide for safety reasons.\415\ EEI also
noted that in comments filed in response to the NOI, the Nuclear Energy
Institute pointed out that nuclear plants are not well-suited to
provide primary frequency response, and emphasized the role of the NRC
as the safety regulator for commercial nuclear operations and its
regulatory restrictions on NRC licenses.\416\ MISO TOs assert that
nuclear generating facilities generally have turbine controls, which
are designed to maintain steam pressure and do not respond to grid
frequency deviations, and that because primary frequency response is
automatic, unsupervised and unplanned maneuvering of a nuclear reactor
can lead to safety issues.\417\
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\414\ See, e.g., AES Companies Comments at 7; MISO TOs Comments
at 8, 13-14; EEI Comments at 14; NRECA Comments at 3; PG&E Comments
at 2; SoCal Edison Comments at 4; TVA Comments at 3; Xcel Comments
at 8.
\415\ EEI Comments at 14; MISO TOs Comments at 13.
\416\ EEI Comments at 14.
\417\ MISO TOs Comments at 13-14.
---------------------------------------------------------------------------
200. On the other hand, other commenters believe that the
Commission should not automatically exempt new nuclear generating
facilities. WIRAB asserts that the Commission should require new
nuclear generating facilities to seek individual exemptions, as needed,
based on legitimate safety requirements in their NRC operating
license.\418\ WIRAB contends that in the future, new nuclear generating
facilities in the U.S. may have the capability to safely and reliably
respond to frequency deviations, and therefore the Commission should
not provide an automatic exemption.\419\
---------------------------------------------------------------------------
\418\ WIRAB Comments at 7-8.
\419\ Id.
---------------------------------------------------------------------------
201. Similarly, ISO-RTO Council believes that the Commission should
not ``anticipate'' exemption requirements. Instead, ``any pro forma
exemptions to the requirement to provide frequency response, including
exemptions for new nuclear units, should be supported by applicable
regulatory requirements, such as NRC rules and any regional
requirements demonstrated by the nuclear owner to be applicable to the
particular unit or type of unit.'' \420\
---------------------------------------------------------------------------
\420\ ISO-RTO Council Comments at 7.
---------------------------------------------------------------------------
c. Commission Determination
202. We adopt the NOPR proposal to exempt nuclear generating
facilities from the final action requirements, due to the unique
regulatory and technical requirements of nuclear generating facilities.
As explained in the NOPR, nuclear generating facilities have separate
licensing requirements under the NRC, which often restrict or severely
limit nuclear generating facilities from providing primary frequency
response.\421\ Further, nuclear generating facilities are designed to
maintain internal steam pressure and are not intended to react to
changes in the grid.\422\
---------------------------------------------------------------------------
\421\ NOPR, 157 FERC ] 61,122 at P 31.
\422\ Id.
---------------------------------------------------------------------------
203. We disagree with WIRAB's and ISO-RTO Council's view that an
entire class of generating facilities should not be exempted from the
pro forma requirements. We find that the unique regulatory and
technical requirements of nuclear facilities justify an exemption.
Requiring nuclear generating facilities to request unit-specific
exemptions from providing a service that their licensing requirements
already limit or restrict could result in an unreasonable
administrative burden that can be avoided by allowing a general
exemption in the pro forma LGIA and pro forma SGIA, and we do so here.
5. Wind Generating Facilities
a. NOPR Proposal
204. In the NOPR, the Commission did not propose to exempt new wind
generating facilities from the new primary frequency response
requirements. The Commission observed that while primary frequency
response functionality has not been a standard feature on non-
synchronous generating facilities, recent technological advancements
have equipped wind generating facilities with this capability. The
Commission further noted that wind generating facilities typically
operate at their maximum operating output, and generally lack excess
capacity (or headroom) to provide primary frequency response during
under-frequency conditions.\423\
---------------------------------------------------------------------------
\423\ NOPR, 157 FERC ] 61,122 at P 13.
---------------------------------------------------------------------------
b. Comments
205. AWEA states that the Commission's proposed addition of a
primary frequency response requirement to the pro forma LGIA and pro
forma SGIA can be met at low cost for new wind projects, and therefore
new wind turbines should not have difficulty complying with the
Commission's proposal.\424\ AWEA further states that it does not oppose
the addition of the proposed primary frequency response capability
requirement to interconnection standards for new non-synchronous
generators, and that the proposed deadband and response rates for
capability settings of maximum 5 percent droop and 0.036 Hz
deadband appear reasonable and consistent with industry practice.\425\
---------------------------------------------------------------------------
\424\ AWEA Comments at 4.
\425\ Id. at 4-5.
---------------------------------------------------------------------------
206. However, Sunflower and Mid-Kansas contend that, given current
adequate frequency response performance and a lack of sufficient data
in the record on the extent to which primary frequency response is
needed from wind generating facilities, the Commission should not adopt
a blanket requirement that includes wind generating facilities at this
time. Sunflower and Mid-Kansas assert that the Commission should
instead proceed with further analysis first, as contemplated by NERC,
or at least allow for flexibility in the requirements.\426\
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\426\ Sunflower and Mid-Kansas Comments at 4.
---------------------------------------------------------------------------
c. Commission Determination
207. We are not persuaded by Sunflower and Mid-Kansas to exempt
wind generating facilities from the primary frequency response
[[Page 9666]]
requirements of this final action. As discussed above, a key focus of
this final action is the ongoing shift of the generation resource mix,
with declining amounts of traditional synchronous generating facilities
that historically have provided primary frequency response and
increasing penetrations of non-synchronous generation, including wind
generating facilities that historically have not been a significant
source of primary frequency response. Unlike certain CHP or nuclear
generating facilities, the record does not indicate that there is an
economic, technical, or regulatory basis for a generic exemption for
newly interconnecting wind generating facilities. In particular, we are
persuaded by AWEA's assertion that the proposed primary frequency
response capability requirements can be met at low cost for new wind
projects, and that newly interconnecting wind facilities should not
have difficulty complying with the proposed deadband of 0.036 Hz and a maximum 5 percent droop parameter.\427\
Accordingly, we will not exempt wind generating facilities from the
requirements of this final action.
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\427\ AWEA Comments at 4.
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6. Surplus Interconnection
a. NOPR Proposal
208. In the NOPR, the Commission did not propose any provisions
related to surplus interconnection service.\428\
---------------------------------------------------------------------------
\428\ See Reform of Generator Interconnection Procedures and
Agreements, Notice of Proposed Rulemaking, 82 FR 4464 (Jan. 13,
2017), 157 FERC ] 61,212 (2016). Surplus interconnection service
refers to an instance where an interconnection customer has an
interconnection agreement which provides more interconnection
service than it currently uses, and may wish to add resources, such
as electric storage resources, which were not planned with part of
the original interconnection request, or it may wish to sell surplus
interconnection service without conveying the originally planned
generating facility as part of the sale.
---------------------------------------------------------------------------
b. Comments
209. ESA states that the Commission recently issued a NOPR which
proposes to make available the use of surplus interconnection service,
which is intended to maximize the use of existing interconnection
service capacity and concerns generating facilities that are existing
interconnection customers.\429\ ESA contends that these forms of
interconnections should not be considered ``new interconnection'' for
the purposes of primary frequency response capability requirements, and
requests that the Commission exempt surplus interconnection services
from its proposed primary frequency response requirements.\430\
---------------------------------------------------------------------------
\429\ ESA Comments at 5.
\430\ Id.
---------------------------------------------------------------------------
c. Commission Determination
210. We find that ESA's request that surplus interconnection
service should not be considered ``new interconnection'' for purposes
of this final action is premature, because the Commission has yet to
issue any final action that addresses surplus interconnection
service.\431\
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\431\ We further note that MISO's Net Zero Interconnection
Service is an interconnection request that results in a GIA. As
such, a generator connecting to the transmission system using Net
Zero Interconnection Service would be expected to comply with this
final action. See MISO Tariff Attachment X 3.3.1.1 (Additional
Requirements for a Net Zero Interconnection Request application).
---------------------------------------------------------------------------
7. Small Generating Facilities
a. NOPR Proposal
211. In the NOPR, the Commission proposed to apply the proposed
requirements to newly interconnecting small generating facilities. The
Commission stated that the record suggests that small generating
facilities are capable of installing and enabling governors at low cost
in a manner comparable to large generating facilities.\432\ The
Commission concluded that given recent technological advances, the
Commission did not anticipate that requiring the pro forma SGIA to be
amended to include requirements for primary frequency response
capability would present a barrier for small generating facilities,
and, given the need for additional primary frequency response
capability and an increasingly large market penetration of small
generating facilities, the Commission believed that there is a need to
add these requirements to the pro forma SGIA to help ensure primary
frequency response capability. In support, the Commission referenced
PJM's recent changes to its interconnection agreements to require new
large and small non-synchronous generating facilities to install
enhanced inverters, which include primary frequency response capability
requirements.\433\
---------------------------------------------------------------------------
\432\ NOPR, 157 FERC ] 61,122 at P 41 (citing IEEE-P1547 Working
Group NOI Comments at 1, 5, and 7).
\433\ Id. P 42.
---------------------------------------------------------------------------
b. Comments
i. NOPR Comments
212. Most commenters who generally supported the NOPR's proposal
did not differentiate between small and large generators. APPA et al.
contends applying the primary frequency response requirement to all
generators is important, particularly given that non-synchronous
generators and small generators are making up a growing share of the
changing generation resource mix.\434\ EEI states that it supports the
Commission acting to remove inconsistencies between the pro forma LGIA
and the pro forma SGIA because there is no economical or technical
basis for treating large and small generating facilities differently
when they are both capable of installing and enabling governors at
comparable costs.\435\
---------------------------------------------------------------------------
\434\ APPA et al. Comments at 5.
\435\ EEI Comments at 8.
---------------------------------------------------------------------------
213. Some commenters,\436\ however, raise concerns that small
generating facilities could face disproportionate costs to install
primary frequency response capability. For example, the Public Interest
Organizations argue that the Commission's discussion of the economic
impact on small generating facilities of installing primary frequency
response capability is limited, and claimed the cited evidence in the
NOPR does not directly support the Commission's conclusion that ``small
generating facilities are capable of installing and enabling governors
at low cost in a manner comparable to large generating facilities.''
\437\ In support of their position, Public Interest Organizations note
SolarCity Corporation's concern that ``a requirement that all
generating facilities have frequency response capability may cost more
for some resources, including behind-the-meter and distributed energy
resources.'' \438\ Public Interest Organizations state that they
therefore encourage the Commission to further investigate the cost for
small renewable energy generating facilities to install frequency
response capability before making the proposed revisions to the pro
forma SGIA.\439\
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\436\ See NRECA Comments at 8; Public Interest Organizations
Comments at 3; TVA Comments at 4; Idaho Power Comments at 2.
\437\ Public Interest Organizations Comments at 3 (citing NOPR,
157 FERC ] 61,122 at P 42).
\438\ Id. at 3 (citing SolarCity Corporation's NOI Comments at
4).
\439\ Id. at 3-4.
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214. Other commenters request the Commission adopt a size
limitation for applying the NOPR requirements. For example, TVA
requests an exemption for generating facilities under 5 MVA as long as
they do not aggregate with facilities greater than 75 MVA or connect to
the grid at 100 kV or above.\440\ Similarly, Idaho Power and NRECA
request that the Commission consider exempting generating facilities
[[Page 9667]]
that are smaller than 10 MW. Idaho Power states that it would be
difficult to determine compliance if the required response is too
small.\441\ NRECA suggests that small generating facilities might have
a different cost-benefit analysis than large generating facilities, and
asserts that there is not a sufficient record to conclude that the
proposed requirement to install primary frequency response capability
will not pose an undue burden on smaller generating facilities.\442\
---------------------------------------------------------------------------
\440\ TVA Comments at 4.
\441\ Idaho Power Comments at 2.
\442\ NRECA Comments at 8.
---------------------------------------------------------------------------
ii. Supplemental Comments
215. NAGF, Tri-State, ISO-RTO Council, SoCal Edison, and WIRAB
support applying the proposed requirements to small generating
facilities.\443\ ISO-RTO Council states that the proposed requirements
are consistent with the current requirements of PJM, NYISO, ISO-NE, and
CAISO, all of which require small generators to install, maintain, and
operate equipment capable of providing primary frequency response as a
condition of interconnection.\444\ ISO-RTO Council contends that these
requirements have been in place for several years, have not resulted in
operational issues or challenges associated with such requirements, and
have not required exemptions for small generators.\445\
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\443\ NAGF Supplemental Comments at 2; Tri-State Supplemental
Comments at 3; ISO-RTO Council Supplemental Comments at 6; SoCal
Edison Supplemental Comments at 2; WIRAB Supplemental Comments at 7.
\444\ ISO-RTO Supplemental Comments at 3.
\445\ ISO-RTO Council Supplemental Comments at 4.
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216. Further, ISO-RTO Council asserts that ``providing an exemption
or variation to the NOPR requirements for small generators and electric
storage resources could allow such resources to avoid solving the very
problem to which such resources contribute and the NOPR rules were
meant to address.'' \446\ In particular, ISO-RTO Council points out
that the ongoing transformation of the generation resource mix involves
the loss of the inertia and primary frequency response contributions
from baseload and synchronous generating facilities that have and will
retire. Since non-synchronous generators, small generators, distributed
energy resources, and electric storage resources will comprise an
increasing percentage of the future generation mix, ISO-RTO Council
states that they should contribute their fair share of primary
frequency response in accordance with the requirements proposed in the
NOPR.\447\
---------------------------------------------------------------------------
\446\ Id. at 2.
\447\ Id. at 2, 3.
---------------------------------------------------------------------------
217. EEI adds that as the market penetration of small generating
facilities increases, there will be a growing need for primary
frequency response from these non-traditional generating
facilities.\448\ EEI argues that ``[i]f the Commission exempts new
small generating resources from installing primary frequency response
capability now, then retrofitting them may be needed in the future to
address reliability concerns, which will be more costly.'' \449\ EEI
states, however, that the potential costs for small generating
facilities can be reduced if the Commission limits its proposal to
solely installing primary frequency response capability and not
adopting the proposed operating requirements for droop, deadband, and
timely and sustained response in the pro forma LGIA and pro forma
SGIA.\450\
---------------------------------------------------------------------------
\448\ EEI Supplemental Comments at 8.
\449\ Id.
\450\ Id. at 4.
---------------------------------------------------------------------------
218. APS suggests that all generating facilities should contribute
to primary frequency response and opposes a blanket exemption for small
generating facilities. Rather, APS suggests that determining whether
and how small generating facilities contribute to primary frequency
response should be a collaborative effort among the balancing
authority, transmission provider, and interconnection customer.\451\
---------------------------------------------------------------------------
\451\ APS Supplemental Comments at 10-11.
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219. While AES Companies oppose the NOPR, they state that the size
of any particular generating facility should not impact the solution
implemented.\452\ NRECA agrees that there should be flexibility for
balancing authorities, RTOs/ISOs, or other public utility transmission
providers to adopt requirements for primary frequency response
capability in response to specific concerns in their regions in
instances where generating facilities have particular operating or
other characteristics which make it unreasonable from a cost-benefit or
technical perspective to require primary frequency response capability
as a condition precedent to interconnection.\453\ SDG&E remains
concerned that unnecessary capital costs will be incurred if the
Commission chooses to require all new generators to have primary
frequency response capability, and that generation owners will attempt
to pass those costs along to consumers.\454\
---------------------------------------------------------------------------
\452\ AES Companies Supplemental Comments at 42.
\453\ NRECA Supplemental Comments at 2-3.
\454\ SDG&E Supplemental Comments at 3-4.
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220. Finally, Sunrun states that even inverters certified to UL
1741 SA \455\ may or may not have certified frequency-watt response
capability, as it is not required for California's phase one advanced
inverter implementation, and even the most progressive state-level
inverter function requirements may fall short of enabling primary
frequency response capability, leaving a number of important unknowns
to small systems also needing to aggregate and participate in wholesale
markets.\456\
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\455\ The UL 1741 Standard is intended for use with distributed
energy resources. See UL 1741, Standard for Inverters, Converters,
Controllers, and Interconnection System Equipment for Use with
Distributed Energy Resources, https://standardscatalog.ul.com/standards/en/standard_1741_2. The Commission discusses the
applicability of the final action to distributed energy resources in
Section II.H.3.
\456\ Sunrun Supplemental Comments at 3-4.
---------------------------------------------------------------------------
221. In response to the Commission's question about whether the
costs for small generating facilities to install, maintain, and operate
governors or equivalent controls are proportionally comparable to the
costs for large generating facilities, NRECA states that a size
threshold is necessary so that small generators will not be forced to
forego interconnection because the cost of including primary frequency
response capability outweighs the benefit of interconnection.\457\
However, WIRAB states that costs for inverters capable of providing
primary frequency response have declined. WIRAB submits that in 2013,
the cost between a traditional inverter and an inverter capable of
providing primary frequency response was less than 1 percent of the
overall project. WIRAB adds that it is now standard practice to install
such inverters for all utility scale, non-synchronous generating
facilities because operational changes and updates can be made through
software changes.\458\ Further, WIRAB states that if the Commission
determines that small generating facilities may experience
disproportionate cost impacts associated with the proposed requirement,
the Commission should establish an exemption that would allow small
generators to provide a demonstration of disproportionate costs to its
utility to be exempt from the primary frequency response
requirements.\459\ SoCal Edison agrees that given significant
technological advances in generation facilities and equipment,
including inverters, the proposed primary
[[Page 9668]]
frequency response requirements for small generating facilities will
not present a barrier to entry.\460\
---------------------------------------------------------------------------
\457\ NRECA Supplemental Comments at 4.
\458\ WIRAB Supplemental Comments at 6-7.
\459\ Id. at 7.
\460\ SoCal Edison Supplemental Comments at 3.
---------------------------------------------------------------------------
222. In response to the Commission's question about whether PJM's
recent modifications to its interconnection agreements address concerns
regarding possible disproportionate costs resulting from applying the
NOPR to all small generating facilities, ISO-RTO Council states that
PJM has not experienced any decrease in the number of interconnection
requests of small non-synchronous generators since requiring non-
synchronous generating facilities to install enhanced inverters that
include primary frequency response capability.\461\ ISO-RTO Council
states that in the last year, 30 new generating facilities were placed
into service, and of those, 25 were small generating facilities and
five were large generating facilities.\462\
---------------------------------------------------------------------------
\461\ ISO-RTO Supplemental Comments at 6.
\462\ Id. at 7.
---------------------------------------------------------------------------
c. Commission Determination
223. We will not exempt small generating facilities from the
requirements. The Commission has previously acted under FPA section 206
to remove inconsistencies between the pro forma LGIA and pro forma SGIA
where there is no economic or technical basis for treating large and
small generating facilities differently.\463\ The record indicates that
small generating facilities are capable of installing and enabling
governors or equivalent technologies at low cost in a manner comparable
to large generating facilities; therefore it would be unduly
discriminatory or preferential to not impose the requirements of this
final action on small generating facilities. There is limited and
unpersuasive information in the record indicating that certain small
generating facilities would face disproportionate costs to install,
maintain, and operate equipment capable of providing primary frequency
response. Moreover, the record demonstrates that small generating
facilities are technically capable of providing primary frequency
response. No commenter provided evidence to suggest that imposing the
requirements of this final action on small generators would be
disproportionately costly or otherwise unduly burdensome.
---------------------------------------------------------------------------
\463\ See Order No. 828, 156 FERC ] 61,062 (revising the pro
forma SGIA such that small generating facilities have frequency and
voltage ride through requirements comparable to large generating
facilities).
---------------------------------------------------------------------------
224. In particular, we are persuaded by commenter assertions that
that small generating facilities are making up a growing percentage of
the generation resource mix,\464\ and that as the market penetration of
small generating facilities increases, there will be a growing need for
primary frequency response from these generating facilities.\465\ We
are also persuaded by commenter assertions that there is no economical
or technical basis for treating large and small generating facilities
differently when they are both capable of installing and enabling
governors at comparable costs.\466\ Finally, we do not believe that the
actions we take here will present a barrier to entry to small
generating facilities. We note ISO-RTO Council's assertion that ``PJM
has not experienced any decrease in the number of interconnections
requests or interconnections of small non-synchronous generators since
requiring nonsynchronous generating facilities to install enhanced
inverters that include primary frequency response capability.'' \467\
---------------------------------------------------------------------------
\464\ APPA et al. Comments at 5.
\465\ EEI Comments at 8.
\466\ SoCal Edison Comments at 3.
\467\ ISO-RTO Council Supplemental Comments at 7.
---------------------------------------------------------------------------
8. Requests To Establish a Waiver Process and Consider Potential Impact
on Load and New Technology
a. NOPR
225. In the NOPR, the Commission did not propose any waiver
procedures.
b. Comments
226. NRECA requests that the Commission consider permitting
transmission providers to establish ``penetration level thresholds''
for primary frequency response because ``[g]enerators can differ in
their impact on the transmission grid based on factors such as size and
technology.'' \468\ NRECA contends that in areas with sufficient
primary frequency response capability, including the cost of primary
frequency response in new generating facilities may not necessarily be
warranted and should therefore not be required as a condition of
interconnection.\469\ NRECA further asserts that the Commission should
``bear in mind that the costs for frequency response capability will be
recovered from load. Customers should not have to pay for capability
that is not necessary for reliability.'' \470\
---------------------------------------------------------------------------
\468\ NRECA Comments at 8.
\469\ Id.
\470\ Id. at 9.
---------------------------------------------------------------------------
227. Both NRECA and AES Companies express concern about the
potential impact of the proposed requirements on new technologies and
innovation. AES Companies assert that the proposed requirements for new
generating facilities to install primary frequency response capability
as well operate with specified droop and deadband settings will
``stymie the use of more efficient technology solutions as they become
available and impose unnecessary costs on load.'' \471\ Similarly,
NRECA is concerned that the Commission's ``all-encompassing proposal''
could risk limiting ``the deployment of the sorts of technologies and
innovation which the Commission has pledged to encourage, without
conferring reliability benefits that warrant such risks.'' \472\
---------------------------------------------------------------------------
\471\ AES Companies Comments at 12.
\472\ NRECA Comments at 6.
---------------------------------------------------------------------------
228. NRECA contends that the Commission should adopt ``a waiver
process whereby if a new interconnecting generating facility is neither
needed for primary frequency response capability, nor causes any harm
to the reliability of the grid in this regard, primary frequency
response capability would not be a condition of interconnection.''
\473\
---------------------------------------------------------------------------
\473\ Id. at 8-9.
---------------------------------------------------------------------------
c. Commission Determination
229. We decline to adopt a waiver process for new generating
facilities. Considering the dynamic and evolving nature of primary
frequency response, we are not persuaded by NRECA's suggestion that the
current specific needs of individual balancing authority areas within
each Interconnection should determine whether to adopt minimum uniform
primary frequency response requirements as a condition of
interconnection. While the level of primary frequency response
capability may be adequate in certain individual areas, NERC
assessments indicate that the Bulk-Power System as a whole has
experienced a decline in primary frequency response. In this regard, we
reject NRECA's suggestion that ``an imminent reliability threat'' must
exist to justify new primary frequency requirements such as those we
adopt in this final action.\474\ We clarify that this final action is
intended to ensure that the overall level of primary frequency response
capability remains adequate as the generation resource mix continues to
change. Accordingly, we decline NRECA's request to develop a generic
waiver process to exempt newly interconnecting generating facilities
from the requirements of this final action.
---------------------------------------------------------------------------
\474\ Id. at 7.
---------------------------------------------------------------------------
230. In addition, we disagree with NRECA and AES Companies that
this
[[Page 9669]]
final action will result in unreasonable or unnecessary costs to load,
based on the record indicating that cost of installing primary
frequency response capability for new generating facilities is minimal.
As explained in Section II.E.2 above, many commenters agree that costs
associated with primary frequency response are minimal for new
generating facilities.
231. Finally, we find NRECA's and AES Companies' assertions
regarding the potential adverse impact of the new primary frequency
requirements adopted in this final action on technology and innovation
to be speculative and unsupported. In this regard, we clarify that
should the new primary frequency response requirements present
obstacles to new, more efficient generating facilities that may be
developed in the future, nothing in this final action prohibits
prospective interconnection customers owning such facilities from
seeking appropriate relief from the Commission.
I. Regional Flexibility
1. NOPR Proposal
232. In the NOPR, the Commission proposed that public utility
transmission providers must either comply with the final action,
demonstrate that previously-approved variations continue to be
consistent with or superior to the pro forma LGIA and pro forma SGIA as
modified by the final action, or seek ``independent entity variations''
from the proposed revisions to the pro forma LGIA and pro forma
SGIA.\475\
---------------------------------------------------------------------------
\475\ NOPR, 157 FERC ] 61,122 at P 59. See Order No. 2003, FERC
Stats. & Regs. ] 31,146 at PP 822-827.
---------------------------------------------------------------------------
2. Comments
233. Some commenters object to the proposal to make operating
requirements uniform, contending that such uniformity fails to account
for differences across regions and generating facilities--particularly
those utilizing new technology and fuel sources--and the actual need
for primary frequency response.\476\
---------------------------------------------------------------------------
\476\ See, e.g., APS Supplemental Comments at 5-6; MISO TOs
Comments at 2; SoCal Edison Comments at 3; Xcel Comments at 7; NYTO
Supplemental Comments at 3-4.
---------------------------------------------------------------------------
3. Commission Determination
234. As explained above in Section II.B.3.a, we disagree with
commenters who support a completely regional approach. We believe that
the most effective approach to addressing concerns regarding primary
frequency response is to establish and maintain minimum, uniform
requirements for all newly interconnecting generating facilities.
However, we recognize that unique circumstances or needs of some
individual regions or areas may warrant different operating
requirements. Therefore, we adopt the NOPR proposal and will allow
transmission providers to propose variations to the operating
requirements adopted in this final action. Specifically, the following
methods for proposing variations adopted in Order No. 2003 will be
available here: (1) Variations based on Regional Entity reliability
requirements; (2) variations that are ``consistent with or superior
to'' the final action; and (3) ``independent entity variations'' filed
by RTOs/ISOs.\477\
---------------------------------------------------------------------------
\477\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 822-
827. A very similar approach was taken in Order No. 827, FERC Stats.
& Regs. ] 31,385 at P 69 and Order No. 828, 156 FERC ] 61,062 at PP
40-41.
---------------------------------------------------------------------------
235. Finally, we clarify that the Commission will also consider
requests for ``regional reliability variations,'' provided they are
supported by references to regional Reliability Standards. In addition,
in any such request, the transmission provider shall explain why these
regional Reliability Standards support the requested variation, and
shall include the text of the referenced Reliability Standards.\478\
---------------------------------------------------------------------------
\478\ See Order No. 2006, FERC Stats. & Regs. ] 31,180 at P 546.
---------------------------------------------------------------------------
J. Miscellaneous Comments
1. Uniform System of Accounts
a. Comments
236. Xcel states that the Commission should add a new account to
the FERC Uniform System of Accounts to allow the identification and
tracking of cost information associated with primary frequency
response. Xcel argues that a new FERC account would allow for the
collection of installed cost information ``so that the Commission can
ensure that any rates reflect those costs and recover the costs form
the appropriate customer base (i.e., transmission versus production
customers).'' \479\
---------------------------------------------------------------------------
\479\ Xcel Comments at 9-10.
---------------------------------------------------------------------------
b. Commission Determination
237. We deny this request. First, the costs of installing,
maintaining, and operating a governor or equivalent controls is not
significant and is captured by other accounts.\480\ Second, synchronous
generating facilities have installed, maintained, and operated
governors for many years and Xcel has not demonstrated why changed
circumstances require new accounts to capture these costs. It is also
not clear why these existing accounts could not similarly be applied to
non-synchronous generating facilities.
---------------------------------------------------------------------------
\480\ Examples of these other accounts are described in Appendix
C of this final action.
---------------------------------------------------------------------------
2. Capability of Load To Provide Primary Frequency Response
a. Comments
238. Union of Concerned Scientists asserts that while it believes
that the NOPR proposal is ``an important step'' and the Commission
should ``complete this rulemaking,'' the NOPR proposal ``omit[s]
discussion of how the utility industry may draw on the capability of
loads to provide frequency response.'' \481\ Accordingly, Union of
Concerned Scientists urges the Commission to ``guide utilities to
include load resources in the development of primary frequency response
services and requirements.'' \482\ Union of Concerned Scientists
maintains that the NOPR proposal is a necessary, but insufficient, step
in addressing primary frequency response because: (1) The NOPR excludes
load from consideration as a primary frequency response resource; and
(2) the reliance on headrooT from generating facilities for the
provision of primary frequency response results in a greater economic
cost to generating facilities compared to the zero marginal cost of
load as a resource for providing primary frequency response.\483\
---------------------------------------------------------------------------
\481\ Union of Concerned Scientists Comments at 3.
\482\ Id. at 8.
\483\ Id. at 7-8.
---------------------------------------------------------------------------
b. Commission Determination
239. We decline in this final action to address the need for load
resources to provide primary frequency response. While we note that
there are many complicated issues related to the provision of primary
frequency response by load resources, we find that these issues are
beyond the scope of this proceeding, which is limited to modifications
to the pro forma LGIA and the pro forma SGIA. We recognize that
currently some load resources can and do provide some primary frequency
response. Nothing in this final action is meant to discourage or
prevent them from doing so.
3. Primary Frequency Response Obligations and Pools
a. Comments
240. AES Companies state that NERC's Essential Reliability Services
Task Force recommended that all new generating facilities should
support the capability to manage frequency control, not that they
should provide primary
[[Page 9670]]
frequency response themselves.\484\ As a result, AES Companies suggest
that the Commission modify the NOPR proposal to allow the
interconnection customer to demonstrate that they can provide its
proportional share of primary frequency response, either through self-
supply from other generating facilities within its fleet or via
procurement from a third party.\485\ AES Companies further suggest that
utilities and other generation owners should then be allowed to form
pools and/or aggregate their resources to meet an allocated
proportionate share of their primary frequency response
responsibility.\486\
---------------------------------------------------------------------------
\484\ AES Companies Comments at 12.
\485\ Id.
\486\ Id.
---------------------------------------------------------------------------
b. Commission Determination
241. We reject AES Companies' suggestions. Adopting these
suggestions would add complications and create substantial uncertainty
for generating facilities providing primary frequency response, which
will detract from one of the Commission's goals (i.e., minimizing
complexity and uncertainty with regard to primary frequency response).
K. Specific Revisions to the Pro Forma LGIA and Pro Forma SGIA
1. NOPR Proposal
242. To implement the proposed primary frequency response
requirements, the Commission proposed in the NOPR to revise Sections
9.6 and 9.6.2.1 of the pro forma LGIA and add new Sections 9.6.4,
9.6.4.1, and 9.6.4.2 to the pro forma LGIA.\487\ Similarly, the
Commission proposed to revise Section 1.8 of the pro forma SGIA and add
new Sections 1.8.4, 1.8.4.1, and 1.8.4.2 to the pro forma SGIA.\488\
---------------------------------------------------------------------------
\487\ NOPR, 157 FERC ] 61,122 at P 52.
\488\ Id. P 53.
---------------------------------------------------------------------------
2. Comments
243. As noted above in Sections II.B.2.a, II.B.2.b, II.B.2.c,
II.C.2, II.H.1.b, and II.H.2.b of this final action, Bonneville, EEI,
ELCON, NERC, ISO-RTO Council, and WIRAB request certain modifications
to the proposed changes to pro forma LGIA and pro forma SGIA as
discussed in the NOPR. AES Companies also request to modify Section 9.6
of the pro forma LGIA.\489\
---------------------------------------------------------------------------
\489\ AES Companies Comments at 15.
---------------------------------------------------------------------------
3. Commission Determination
244. We deny AES Companies' request to modify Section 9.6 of the
pro forma LGIA as the request is related to reactive power and thus
beyond the scope of this proceeding. We also deny AES Companies other
proposed modifications to the pro forma LGIA and pro forma SGIA.
245. Further, as explained in Sections II.B and II.C above, we
conclude that EEI's requested modifications to the proposed revisions
in the pro forma LGIA and pro forma SGIA that undermine uniformity are
not consistent with the objectives explained herein and therefore are
denied. However, we adopt EEI's requested language pertaining to timely
and sustained response, particularly the phrase ``shall not block or
inhibit governor or equivalent controls.''
246. In light of the above discussion, we revise the pro forma LGIA
to modify Sections 9.6 and 9.6.2.1 and adds new Sections 9.6.4,
9.6.4.1, 9.6.4.2, 9.6.4.3, and 9.6.4.4. This section contains the
totality of the revised revisions the pro forma LGIA. The revisions,
with bracketed deletions from and italicized additions to the pro forma
LGIA are as follows:
9.6 Reactive Power and Primary Frequency Response
9.6.2.1 [Governors and] Voltage Regulators. Whenever the Large
Generating Facility is operated in parallel with the Transmission
System [and the speed governors (if installed on the generating unit
pursuant to Good Utility Practice)] and voltage regulators are capable
of operation, Interconnection Customer shall operate the Large
Generating Facility with its [speed governors and] voltage regulators
in automatic operation. If the Large Generating Facility's [speed
governors and] voltage regulators are not capable of such automatic
operation, Interconnection Customer shall immediately notify
Transmission Provider's system operator, or its designated
representative, and ensure that such Large Generating Facility's
reactive power production or absorption (measured in MVARs) are within
the design capability of the Large Generating Facility's generating
unit(s) and steady state stability limits. Interconnection Customer
shall not cause its Large Generating Facility to disconnect
automatically or instantaneously from the Transmission System or trip
any generating unit comprising the Large Generating Facility for an
under or over frequency condition unless the abnormal frequency
condition persists for a time period beyond the limits set forth in
ANSI/IEEE Standard C37.106, or such other standard as applied to other
generators in the Control Area on a comparable basis. (Bracketed text
is deleted, italicized text are additions.)
9.6.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Large
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Large Generating Facility's real
power output in accordance with the droop and deadband parameters and
in the direction needed to correct frequency deviations.
Interconnection Customer is required to install a governor or
equivalent controls with the capability of operating: (1) With a
maximum 5 percent droop and 0.036 Hz deadband; or
(2) in accordance with the relevant droop, deadband, and timely and
sustained response settings from an approved NERC Reliability Standard
providing for equivalent or more stringent parameters. The droop
characteristic shall be: (1) Based on the nameplate capacity of the
Large Generating Facility, and shall be linear in the range of
frequencies between 59 to 61 Hz that are outside of the deadband
parameter; or (2) based an approved NERC Reliability Standard providing
for an equivalent or more stringent parameter. The deadband parameter
shall be: the range of frequencies above and below nominal (60 Hz) in
which the governor or equivalent controls is not expected to adjust the
Large Generating Facility's real power output in response to frequency
deviations. The deadband shall be implemented: (1) Without a step to
the droop curve, that is, once the frequency deviation exceeds the
deadband parameter, the expected change in the Large Generating
Facility's real power output in response to frequency deviations shall
start from zero and then increase (for under-frequency deviations) or
decrease (for over-frequency deviations) linearly in proportion to the
magnitude of the frequency deviation; or (2) in accordance with an
approved NERC Reliability Standard providing for an equivalent or more
stringent parameter. Interconnection Customer shall notify Transmission
Provider that the primary frequency response capability of the Large
Generating Facility has been tested and confirmed during commissioning.
Once Interconnection Customer has synchronized the Large Generating
Facility with the
[[Page 9671]]
Transmission System, Interconnection Customer shall operate the Large
Generating Facility consistent with the provisions specified in
Sections 9.6.4.1 and 9.6.4.2 of this Agreement. The primary frequency
response requirements contained herein shall apply to both synchronous
and non-synchronous Large Generating Facilities.
9.6.4.1 Governor or Equivalent Controls. Whenever the Large
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Large Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall: (1) In
coordination with Transmission Provider and/or the relevant balancing
authority, set the deadband parameter to: (1) A maximum of 0.036 Hz and set the droop parameter to a maximum of 5
percent; or (2) implement the relevant droop and deadband settings from
an approved NERC Reliability Standard that provides for equivalent or
more stringent parameters. Interconnection Customer shall be required
to provide the status and settings of the governor or equivalent
controls to Transmission Provider and/or the relevant balancing
authority upon request. If Interconnection Customer needs to operate
the Large Generating Facility with its governor or equivalent controls
not in service, Interconnection Customer shall immediately notify
Transmission Provider and the relevant balancing authority, and provide
both with the following information: (1) The operating status of the
governor or equivalent controls (i.e., whether it is currently out of
service or when it will be taken out of service); (2) the reasons for
removing the governor or equivalent controls from service; and (3) a
reasonable estimate of when the governor or equivalent controls will be
returned to service. Interconnection Customer shall make Reasonable
Efforts to return its governor or equivalent controls into service as
soon as practicable. Interconnection Customer shall make Reasonable
Efforts to keep outages of the Large Generating Facility's governor or
equivalent controls to a minimum whenever the Large Generating Facility
is operated in parallel with the Transmission System.
9.6.4.2 Timely and Sustained Response. Interconnection Customer
shall ensure that the Large Generating Facility's real power response
to sustained frequency deviations outside of the deadband setting is
automatically provided and shall begin immediately after frequency
deviates outside of the deadband, and to the extent the Large
Generating Facility has operating capability in the direction needed to
correct the frequency deviation. Interconnection Customer shall not
block or otherwise inhibit the ability of the governor or equivalent
controls to respond and shall ensure that the response is not
inhibited, except under certain operational constraints including, but
not limited to, ambient temperature limitations, physical energy
limitations, outages of mechanical equipment, or regulatory
requirements. The Large Generating Facility shall sustain the real
power response at least until system frequency returns to a value
within the deadband setting of the governor or equivalent controls. A
Commission-approved Reliability Standard with equivalent or more
stringent requirements shall supersede the above requirements.
9.6.4.3 Exemptions. Large Generating Facilities that are regulated
by the United States Nuclear Regulatory Commission shall be exempt from
Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this Agreement. Large
Generating Facilities that are behind the meter generation that is
sized-to-load (i.e., the thermal load and the generation are near-
balanced in real-time operation and the generation is primarily
controlled to maintain the unique thermal, chemical, or mechanical
output necessary for the operating requirements of its host facility)
shall be required to install primary frequency response capability in
accordance with the droop and deadband capability requirements
specified in Section 9.6.4, but shall be otherwise exempt from the
operating requirements in Sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.4
of this Agreement.
9.6.4.4 Electric Storage Resources. Interconnection Customer
interconnecting an electric storage resource shall establish an
operating range in Appendix C of its LGIA that specifies a minimum
state of charge and a maximum state of charge between which the
electric storage resource will be required to provide primary frequency
response consistent with the conditions set forth in Sections 9.6.4,
9.6.4.1, 9.6.4.2, and 9.6.4.3 of this Agreement. Appendix C shall
specify whether the operating range is static or dynamic, and shall
consider (1) the expected magnitude of frequency deviations in the
interconnection; (2) the expected duration that system frequency will
remain outside of the deadband parameter in the interconnection; (3)
the expected incidence of frequency deviations outside of the deadband
parameter in the interconnection; (4) the physical capabilities of the
electric storage resource; (5) operational limitations of the electric
storage resource due to manufacturer specifications; and (6) any other
relevant factors agreed to by Transmission Provider and Interconnection
Customer, and in consultation with the relevant transmission owner or
balancing authority as appropriate. If the operating range is dynamic,
then Appendix C must establish how frequently the operating range will
be reevaluated and the factors that may be considered during its
reevaluation.
Interconnection Customer's electric storage resource is required to
provide timely and sustained primary frequency response consistent with
Section 9.6.4.2 of this Agreement when it is online and dispatched to
inject electricity to the Transmission System and/or receive
electricity from the Transmission System. This excludes circumstances
when the electric storage resource is not dispatched to inject
electricity to the Transmission System and/or dispatched to receive
electricity from the Transmission System. If Interconnection Customer's
electric storage resource is charging at the time of a frequency
deviation outside of its deadband parameter, it is to increase (for
over-frequency deviations) or decrease (for under-frequency deviations)
the rate at which it is charging in accordance with its droop
parameter. Interconnection Customer's electric storage resource is not
required to change from charging to discharging, or vice versa, unless
the response necessitated by the droop and deadband settings requires
it to do so and it is technically capable of making such a transition.
247. Similarly, the Commission modifies Section 1.8 of the pro
forma SGIA and adds new Sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3,
and 1.8.4.4. This section contains the totality of the revised
revisions the pro forma SGIA. The revisions, with italicized additions
to the pro forma SGIA are as follows:
1.8 Reactive Power and Primary Frequency Response
1.8.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Small
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Small Generating Facility's real
power output
[[Page 9672]]
in accordance with the droop and deadband parameters and in the
direction needed to correct frequency deviations. Interconnection
Customer is required to install a governor or equivalent controls with
the capability of operating: (1) With a maximum 5 percent droop and
0.036 Hz deadband; or (2) in accordance with the relevant
droop, deadband, and timely and sustained response settings from an
approved NERC Reliability Standard providing for equivalent or more
stringent parameters. The droop characteristic shall be: (1) Based on
the nameplate capacity of the Small Generating Facility, and shall be
linear in the range of frequencies between 59 to 61 Hz that are outside
of the deadband parameter; or (2) based an approved NERC Reliability
Standard providing for an equivalent or more stringent parameter. The
deadband parameter shall be: the range of frequencies above and below
nominal (60 Hz) in which the governor or equivalent controls is not
expected to adjust the Small Generating Facility's real power output in
response to frequency deviations. The deadband shall be implemented:
(1) Without a step to the droop curve, that is, once the frequency
deviation exceeds the deadband parameter, the expected change in the
Small Generating Facility's real power output in response to frequency
deviations shall start from zero and then increase (for under-frequency
deviations) or decrease (for over-frequency deviations) linearly in
proportion to the magnitude of the frequency deviation; or (2) in
accordance with an approved NERC Reliability Standard providing for an
equivalent or more stringent parameter. Interconnection Customer shall
notify Transmission Provider that the primary frequency response
capability of the Small Generating Facility has been tested and
confirmed during commissioning. Once Interconnection Customer has
synchronized the Small Generating Facility with the Transmission
System, Interconnection Customer shall operate the Small Generating
Facility consistent with the provisions specified in Sections 1.8.4.1
and 1.8.4.2 of this Agreement. The primary frequency response
requirements contained herein shall apply to both synchronous and non-
synchronous Small Generating Facilities.
1.8.4.1 Governor or Equivalent Controls. Whenever the Small
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Small Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall: (1) In
coordination with Transmission Provider and/or the relevant balancing
authority, set the deadband parameter to: (1) A maximum of 0.036 Hz and set the droop parameter to a maximum of 5
percent; or (2) implement the relevant droop and deadband settings from
an approved NERC Reliability Standard that provides for equivalent or
more stringent parameters. Interconnection Customer shall be required
to provide the status and settings of the governor or equivalent
controls to Transmission Provider and/or the relevant balancing
authority upon request. If Interconnection Customer needs to operate
the Small Generating Facility with its governor or equivalent controls
not in service, Interconnection Customer shall immediately notify
Transmission Provider and the relevant balancing authority, and provide
both with the following information: (1) The operating status of the
governor or equivalent controls (i.e., whether it is currently out of
service or when it will be taken out of service); (2) the reasons for
removing the governor or equivalent controls from service; and (3) a
reasonable estimate of when the governor or equivalent controls will be
returned to service. Interconnection Customer shall make Reasonable
Efforts to return its governor or equivalent controls into service as
soon as practicable. Interconnection Customer shall make Reasonable
Efforts to keep outages of the Small Generating Facility's governor or
equivalent controls to a minimum whenever the Small Generating Facility
is operated in parallel with the Transmission System.
1.8.4.2 Timely and Sustained Response. Interconnection Customer
shall ensure that the Small Generating Facility's real power response
to sustained frequency deviations outside of the deadband setting is
automatically provided and shall begin immediately after frequency
deviates outside of the deadband, and to the extent the Small
Generating Facility has operating capability in the direction needed to
correct the frequency deviation. Interconnection Customer shall not
block or otherwise inhibit the ability of the governor or equivalent
controls to respond and shall ensure that the response is not
inhibited, except under certain operational constraints including, but
not limited to, ambient temperature limitations, physical energy
limitations, outages of mechanical equipment, or regulatory
requirements. The Small Generating Facility shall sustain the real
power response at least until system frequency returns to a value
within the deadband setting of the governor or equivalent controls. A
Commission-approved Reliability Standard with equivalent or more
stringent requirements shall supersede the above requirements.
1.8.4.3 Exemptions. Small Generating Facilities that are regulated
by the United States Nuclear Regulatory Commission shall be exempt from
Sections 1.8.4, 1.8.4.1, and 1.8.4.2 of this Agreement. Small
Generating Facilities that are behind the meter generation that is
sized-to-load (i.e., the thermal load and the generation are near-
balanced in real-time operation and the generation is primarily
controlled to maintain the unique thermal, chemical, or mechanical
output necessary for the operating requirements of its host facility)
shall be required to install primary frequency response capability in
accordance with the droop and deadband capability requirements
specified in Section 1.8.4, but shall be otherwise exempt from the
operating requirements in Sections 1.8.4, 1.8.4.1, 1.8.4.2, and 1.8.4.4
of this Agreement.
1.8.4.4 Electric Storage Resources. Interconnection Customer
interconnecting an electric storage resource shall establish an
operating range in Attachment 5 of its SGIA that specifies a minimum
state of charge and a maximum state of charge between which the
electric storage resource will be required to provide primary frequency
response consistent with the conditions set forth in Sections 1.8.4,
1.8.4.1, 1.8.4.2 and 1.8.4.3 of this Agreement. Attachment 5 shall
specify whether the operating range is static or dynamic, and shall
consider: (1) The expected magnitude of frequency deviations in the
interconnection; (2) the expected duration that system frequency will
remain outside of the deadband parameter in the interconnection; (3)
the expected incidence of frequency deviations outside of the deadband
parameter in the interconnection; (4) the physical capabilities of the
electric storage resource; (5) operational limitations of the electric
storage resource due to manufacturer specifications; and (6) any other
relevant factors agreed to by Transmission Provider and Interconnection
Customer, and in consultation with the relevant transmission owner or
balancing authority as appropriate. If the operating range is dynamic,
then Attachment 5 must establish how frequently the operating range
will be
[[Page 9673]]
reevaluated and the factors that may be considered during its
reevaluation.
Interconnection Customer's electric storage resource is required to
provide timely and sustained primary frequency response consistent with
Section 1.8.4.2 of this Agreement when it is online and dispatched to
inject electricity to the Transmission System and/or receive
electricity from the Transmission System. This excludes circumstances
when the electric storage resource is not dispatched to inject
electricity to the Transmission System and/or dispatched to receive
electricity from the Transmission System. If Interconnection Customer's
electric storage resource is charging at the time of a frequency
deviation outside of its deadband parameter, it is to increase (for
over-frequency deviations) or decrease (for under-frequency deviations)
the rate at which it is charging in accordance with its droop
parameter. Interconnection Customer's electric storage resource is not
required to change from charging to discharging, or vice versa, unless
the response necessitated by the droop and deadband settings requires
it to do so and it is technically capable of making such a transition.
248. The Commission is also modifying the pro forma LGIP and pro
forma SGIP to require newly interconnecting electric storage resources
to include the details of the operating range in their interconnection
request.
249. In particular, the Commission is modifying the following
sections of the pro forma LGIP as indicated below:
Appendix 1 to LGIP Interconnection Request for a Large Generating
Facility
5. Interconnection Customer provides the following information:
h. Primary frequency response operating range for electric storage
resources.
Attachment A to Appendix 1 Interconnection Request
Unit Ratings
Primary frequency response operating range for electric storage
resources:
Minimum State of Charge: __
Maximum State of Charge: __
250. Similarly, the Commission is modifying the following sections
of the pro forma SGIP as indicated below. The revisions, with
italicized additions to pro forma SGIP are as follows:
Attachment 2 Small Generator Interconnection Request (Application Form)
Small Generating Facility Information
Primary frequency response operating range for electric storage
resources:
Minimum State of Charge: __
Maximum State of Charge: __
III. Compliance and Implementation
251. Section 35.28(f)(1) of the Commission's regulations requires
every public utility with a non-discriminatory OATT on file to also
have a pro forma LGIA and pro forma SGIA on file with the
Commission.\490\
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\490\ 18 CFR 35.28(f)(1) (2017).
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252. We reiterate that the requirements of this final action apply
to all newly interconnecting large and small generating facilities that
execute or request the unexecuted filing of a LGIA or SGIA on or after
the effective date of this final action as well as all existing large
and small generating facilities that take any action that requires the
submission of a new interconnection request that results in the filing
of an executed or unexecuted interconnection agreement on or after the
effective date of this final action. We are not requiring changes to
existing interconnection agreements that were executed, or filed
unexecuted, prior to the effective date of this final action.
253. We require each public utility transmission provider that has
a pro forma LGIA and/or pro forma SGIA within its OATT to submit a
compliance filing within 70 days following publication of this final
action in the Federal Register.\491\ The compliance filing must
demonstrate that it meets the requirements set forth in this final
action.
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\491\ For purposes of this final action, a public utility is a
utility that owns, controls, or operates facilities used for
transmitting electric energy in interstate commerce, as defined by
the FPA. See 16 U.S.C. 824(e). A non-public utility that seeks
voluntary compliance with the reciprocity condition of an OATT may
satisfy that condition by filing an OATT, which includes a LGIA and
SGIA.
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254. Some public utility transmission providers may have provisions
in their existing pro forma LGIAs and pro forma SGIAs or other
document(s) subject to the Commission's jurisdiction that the
Commission has deemed to be consistent with or superior to the pro
forma LGIA and pro forma SGIA or are permissible under the independent
entity variation standard or regional reliability standard.\492\ Where
these provisions would be modified by this final action, public utility
transmission providers must either comply with this final action or
demonstrate that these previously-approved variations continue to be
consistent with or superior to the pro forma LGIA and pro forma SGIA as
modified by this final action or continue to be permissible under the
independent entity variation standard or regional Reliability
Standard.\493\
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\492\ See Order No. 792, 145 FERC ] 61,159 at P 270.
\493\ See 18 CFR 35.28(f)(1)(i).
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255. We find that transmission providers that are not public
utilities must adopt the requirements of this final action as a
condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No. 888.\494\
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\494\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,760-63 (1996),
order on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order
on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
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IV. Information Collection Statement
256. The following collection of information contained in this
final action is subject to review by the Office of Management and
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of
1995, 44 U.S.C. 3507(d).\495\ The Paperwork Reduction Act (PRA) \496\
requires each federal agency to seek and obtain Office of Management
and Budget (OMB) approval before undertaking a collection of
information directed to ten or more persons, or contained in a rule of
general applicability. OMB's regulations require the approval of
certain information collection requirements imposed by agency
rules.\497\ Upon approval of a collection of information, OMB will
assign an OMB control number and an expiration date. Respondents
subject to the filing requirements of this proposal will not be
penalized for failing to respond to this collection of information
unless the collection of information displays a valid OMB control
number. Transmission providers and generating facilities are subject to
the proposed revisions to the pro forma LGIA and pro forma SGIA.
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\495\ 44 U.S.C. 3507(d) (2012).
\496\ 44 U.S.C. 3501-3520 (2012).
\497\ 5 CFR 1320.11 (2017).
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257. This final action revises the Commission's pro forma LGIA and
pro forma SGIA in accordance with Sec. 35.28(f)(1) of the Commission's
regulations,\498\ and applies to all newly interconnecting large and
small generating facilities that execute or request the unexecuted
filing of a LGIA or SGIA on or after the effective date of this final
action as well as all existing large and small generating facilities
that
[[Page 9674]]
take any action that requires the submission of a new interconnection
request that results in the filing of an executed or unexecuted
interconnection agreement on or after the effective date of this final
action. Generating facilities subject to this final action will be
required to install, maintain, and operate equipment capable of
providing primary frequency response, consistent with certain operating
requirements for droop, deadband, and timely and sustained response.
The reforms adopted in this final action would require filings of pro
forma LGIAs and pro forma SGIAs with the Commission. We anticipate the
revisions required by this final action, once implemented, will not
significantly change existing burdens on an ongoing basis. With regard
to those public utility transmission providers that believe they
already comply with the revisions adopted in this final action, they
can demonstrate their compliance in the filing required 70 days after
the effective date of this final action. The Commission will submit the
proposed reporting requirements to OMB for its review and approval
under section 3507(d) of the Paperwork Reduction Act.\499\ In the NOPR,
the Commission used FERC-516B as a temporary ``placeholder''
information collection number.\500\ The Commission is now using FERC-
516 information collection because it is no longer pending at OMB in
any actions.
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\498\ 18 CFR 35.28(f)(1) (2017).
\499\ 44 U.S.C. 3507(d).
\500\ The reporting requirements in the NOPR were included under
FERC-516B (OMB Control No. 1902-0286), because FERC-516 was pending
review at OMB in an unrelated action. The reporting requirements in
this final action are included under FERC-516 (OMB Control No. 1902-
0096).
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258. While the Commission expects the revisions adopted in this
final action will provide significant benefits, the Commission
understands that implementation would entail some costs. The Commission
solicited comments on the collection of information and the associated
burden estimate in the NOPR. The Commission did not receive any
comments concerning its burden or cost estimates.
Burden Estimate \501\: Costs to Comply with Paperwork Requirements:
The estimated annual costs are as follows: FERC-516: 74 entities * 1
response/entity (10 hours/response * $74.50/hour) = $56,610.\502\
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\501\ Burden means the total time, effort, or financial
resources expended by persons to generate, maintain, retain,
disclose or provide information to or for a Federal agency,
including: The time, effort, and financial resources necessary to
comply with a collection of information that would be incurred by
persons in the normal course of their activities (e.g., in compiling
and maintaining business records) will be excluded from the
``burden'' if the agency demonstrates that the reporting,
recordkeeping, or disclosure activities needed to comply are usual
and customary.
\502\ The estimates for cost per response are derived using the
following formula: 2017 Average Burden Hours per Response * $76.50
per Hour = Average Cost per Response. The hourly cost figure of
$76.50 is the average FERC employee wage plus benefits. We assume
that respondents earn at a similar rate.
FERC 516 in Final Action, RM16-6
----------------------------------------------------------------------------------------------------------------
Average burden Total annual
Number of Annual number Total number (hours) and burden hours
respondents of responses of responses cost ($) per and total
\503\ per respondent response annual cost ($)
(1) (2) (1) * (2) = (4)............ (3) * (4) = (5)
(3)
----------------------------------------------------------------------------------------------------------------
LGIA & SGIA changes/ 74 1 74 10 hours; 740 hours;
revisions. $765.00. $56,610.00.
-----------------------------------------------------------------------------------
Total................... ................ .............. 74 ............... 740 hours;
$56,610.00.
----------------------------------------------------------------------------------------------------------------
Title: FERC-516, Electric Rate Schedules and Tariff Filings.
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\503\ The NERC Compliance Registry lists 80 entities that
administer a transmission tariff and provide transmission service.
The Commission identifies only 74 as being subject to the proposed
requirements because 6 are Canadian entities and are not under the
Commission's jurisdiction.
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Action: Revision of currently approved collection of information.
OMB Control No.: 1902-0096.
Respondents for this Rulemaking: Businesses or other for profit
and/or not-for-profit institutions.
Frequency of Information: One-time during year 1.
259. Necessity of Information: The Commission is modifying the pro
forma LGIA and pro forma SGIA to require all newly interconnecting
large and small generating facilities, both synchronous and non-
synchronous, to install, maintain, and operate equipment capable of
providing primary frequency response as a condition of interconnection.
Specifically, the Commission is modifying the pro forma LGIA by
revising Sections 9.6 and 9.6.2.1 and adding new Sections 9.6.4,
9.6.4.1, 9.6.4.2 and 9.6.4.3, and is modifying the pro forma SGIA by
revising section 1.8 and adding new Sections 1.8.4, 1.8.4.1, 1.8.4.2,
and 1.8.4.3.
260. Internal Review: The Commission has reviewed the changes and
has determined that the changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has assured itself, by means of internal review, that there
is specific, objective support for the burden estimates associated with
the information collection requirements.
261. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen
Brown, Office of the Executive Director], email:
[email protected], Phone: (202) 502-8663, fax: (202) 273-0873.
262. Comments on the collection of information and the associated
burden estimate in the final action should be sent to the Commission in
this docket and may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW, Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission], at the following email address:
[email protected]. Please reference OMB Control No. 1902-0096
and the docket number of this rulemaking in your submission.
V. Regulatory Flexibility Act
263. The Regulatory Flexibility Act of 1980 (RFA) \504\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities. The RFA does
not mandate any particular outcome in a rulemaking. It only requires
consideration of alternatives that are less burdensome to small
entities and an agency explanation of why alternatives were rejected.
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\504\ 5 U.S.C. 601-612 (2012).
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264. The Small Business Administration (SBA) revised its size
[[Page 9675]]
standards (effective January 22, 2014) for electric utilities from a
standard based on megawatt hours to a standard based on the number of
employees, including affiliates. Under SBA's standards, some
transmission owners will fall under the following category and
associated size threshold: Electric bulk power transmission and
control, at 500 employees.\505\
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\505\ 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121
(Electric Bulk Power Transmission and Control) (2017).
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265. The Commission estimates that the total number of public
utility transmission providers that would have to modify the LGIAs and
SGIAs within their currently effective OATTs is 74.\506\ Of these, the
Commission estimates that approximately 27.5 percent are small
entities. The Commission estimates the average cost to each of these
entities would be minimal, requiring on average 10 hours or $765.00.
According to SBA guidance, the determination of significance of impact
``should be seen as relative to the size of the business, the size of
the competitor's business, and the impact the regulation has on larger
competitors.'' \507\ The Commission does not consider the estimated
burden to be a significant economic impact. As a result, the Commission
certifies that the reforms adopted in this final action would not have
a significant economic impact on a substantial number of small
entities.
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\506\ The NERC Compliance Registry lists 80 entities that
administer a transmission tariff and provide transmission service.
The Commission identifies only 74 as being subject to the proposed
requirements because six are Canadian entities and are not under the
Commission's jurisdiction.
\507\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
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266. The Commission estimates that the total annual number of new
non-synchronous interconnections per year for the first few years of
potential implementation under this rule would be approximately 200,
representing approximately 5,000 MW of installed capacity. For this
analysis, the Commission assumes that all new non-synchronous
interconnections would be small entities.\508\ The Commission estimates
the average total cost to each of these entities would be minimal,
requiring on average approximately $3,300 per MW of installed capacity
for new equipment and software to meet the requirements of this rule,
or an average of $82,500 per entity (this assumes 200 equally sized new
non-synchronous interconnections of 25 MW, actual costs will vary
proportionate to the size of the interconnection).\509\ According to
SBA guidance, the determination of significance of impact ``should be
seen as relative to the size of the business, the size of the
competitor's business, and the impact the regulation has on larger
competitors.'' The Commission does not consider the estimated burden to
be a significant economic impact on these entities because the cost is
relatively minimal compared to the average capital cost per MW for wind
and solar PV generation (approximately 0.20 and 0.19 percent of total
capital costs for wind and solar, respectively).\510\ Additionally, the
Commission does not believe that there would be substantial additional
costs for new synchronous generators because synchronous generators
already come equipped with governors that provide the capability to
provide primary frequency response. Finally, the Commission does not
believe that there would be any overlap between entities that are
public utility transmission providers and new non-synchronous
interconnections. Accordingly, because the Commission believes that
this rule would not have a significant economic impact on a substantial
number of small entities that are public utility transmission providers
and would not have a significant economic impact on a substantial
number of small entities that are new non-synchronous interconnections,
the Commission believes that this rule in its entirety would not have a
significant economic impact on a substantial number of small entities.
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\508\ The threshold for solar and wind generation companies to
be defined as small entities is having less than 250 employees. See
13 CFR 121.201, Sector 22 (Utilities).
\509\ These costs are not relevant to the Paperwork Reduction
Act.
\510\ LBNL estimates that capital cost per MW of installed wind
capacity is $1,690,000. See LBNL 2015 Wind Market Report (Aug.
2016), https://emp.lbl.gov/sites/all/files/2015-windtechreport.final_.pdf. NREL estimates that the capital cost per
MW of installed solar PV capacity is $1,770,000. See NREL U.S.
Photovoltaic Prices and Cost Breakdowns (Sep. 2015), https://www.nrel.gov/docs/fy15osti/64746.pdf.
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VI. Environmental Analysis
267. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\511\ As we
stated in the NOPR, the Commission concludes that neither an
Environmental Assessment nor an Environmental Impact Statement is
required for the revisions adopted in this final action under Sec.
380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\512\ The revisions adopted in this final action would
update and clarify the application of the Commission's standard
interconnection requirements to large and small generating facilities.
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\511\ Regulations Implementing National Environmental Policy
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987) (cross-
referenced at 41 FERC ] 61,284).
\512\ 18 CFR 380.4(a)(15) (2017).
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268. Therefore, this final action falls within the categorical
exemptions provided in the Commission's regulations, and as a result
neither an Environmental Impact Statement nor an Environmental
Assessment is required.
VII. Document Availability
269. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern Standard Time) at 888 First Street NE,
Room 2A, Washington, DC 20426.
270. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number of this document, excluding the last three digits, in
the docket number field.
271. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
VIII. Effective Date and Congressional Notification
272. The final action is effective May 15, 2018. However, as noted
above, the requirements of this final action will apply only to all
newly interconnecting large and small generating facilities that
[[Page 9676]]
execute or request the unexecuted filing of an LGIA or SGIA on or after
the effective date of this final action as well as all existing large
and small generating facilities that take any action that requires the
submission of a new interconnection request that results in the filing
of an executed or unexecuted interconnection agreement on or after the
effective date of this final action. The Commission has determined,
with the concurrence of the Administrator of the Office of Information
and Regulatory Affairs of OMB, that this final action is not a ``major
rule'' as defined in section 351 of the Small Business Regulatory
Enforcement Fairness Act of 1996. This final action is being submitted
to the Senate, House, Government Accountability Office, and Small
Business Administration.
By the Commission.
Issued: February 15, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Note: The following appendices will not appear in the Code of
Federal Regulations.
I. Appendix A: List of Substantive NOPR Commenters (RM16-6-000)
------------------------------------------------------------------------
------------------------------------------------------------------------
AES Companies..................... AES Corporation/AES Energy Storage/
Dayton Power and Light Company/
Indianapolis Power and Light
Company.
APPA et al........................ American Public Power Association/
Large Public Power Council/
Transmission Access Policy Study
Group.
AWEA.............................. American Wind Energy Association.
API............................... American Petroleum Institute.
Bonneville........................ Bonneville Power Administration.
Chelan County..................... Chelan County Public Utility
District.
California Cities................. City of Anaheim/City of Azusa/City
of Banning/City of Colton/City of
Pasadena/City of Riverside.
EEI............................... Edison Electric Institute.
Competitive Suppliers............. Electric Power Supply Association/
Independent Power Producers of New
York/New England Power Generators
Association/Western Power Trading
Forum.
ELCON............................. Electricity Consumers Resource
Council.
ESA............................... Energy Storage Association.
First Solar....................... First Solar, Inc.
Idaho Power....................... Idaho Power Company.
ISO-RTO Council................... ISO-RTO Council.
MISO TOs.......................... Midcontinent Independent System
Operator Transmission Owners.
NRECA............................. National Rural Electric Cooperative
Association.
NERC.............................. North American Electric Reliability
Corporation.
PG&E.............................. Pacific Gas and Electric Company.
Public Interest Organizations..... Public Interest Organizations.
R Street.......................... R Street Institute.
SDG&E............................. San Diego Gas & Electric Company.
SoCal Edison...................... Southern California Edison Company.
Sunflower and Mid-Kansas.......... Sunflower Electric Power Corporation
and Mid-Kansas Electric Company,
LLC.
SVP............................... City of Santa Clara doing business
as Silicon Valley Power.
TVA............................... Tennessee Valley Authority.
Union of Concerned Scientists..... Union of Concerned Scientists.
WIRAB............................. Western Interconnection Regional
Advisory Body.
Xcel.............................. Xcel Energy Services Inc.
------------------------------------------------------------------------
II. Appendix B: List of Substantive Supplemental Commenters (RM16-6-
000)
------------------------------------------------------------------------
------------------------------------------------------------------------
AES Companies..................... AES Corporation/AES Energy Storage/
Dayton Power and Light Company/
Indianapolis Power and Light
Company.
APS............................... Arizona Public Service Company.
Berkshire......................... Berkshire Hathaway Energy.
CESA.............................. California Energy Storage Alliance.
EEI............................... Edison Electric Institute.
EPRI.............................. Electric Power Research Institute.
ESA............................... Energy Storage Association.
Idaho Power....................... Idaho Power Company.
ISO-RTO Council................... ISO-RTO Council.
ITC............................... International Transmission Company.
MCAES............................. Magnum CAES, LLC.
NRECA............................. National Rural Electric Cooperative
Association.
NYTOs............................. New York Transmission Owners.
NERC.............................. North American Electric Reliability
Corporation.
NAGF.............................. North American Generator Forum.
SDG&E............................. San Diego Gas & Electric Company.
SoCal Edison...................... Southern California Edison Company.
Sunrun............................ Sunrun, Inc.
Tri-State......................... Tri-State Generation and
Transmission Association, Inc.
WIRAB............................. Western Interconnection Regional
Advisory Body.
------------------------------------------------------------------------
[[Page 9677]]
III. Appendix C: Uniform System of Accounts
Governor controls and similar electric equipment can be recorded
within the following Uniform System of Accounts account numbers by
function:
Production Plant
a. steam production
313 Engines and engine-driven generators.
314 Turbogenerator units.
315 Accessory electric equipment.
316 Miscellaneous power plant equipment.
b. nuclear production
323 Turbogenerator units (Major only).
324 Accessory electric equipment (Major only).
325 Miscellaneous power plant equipment (Major only).
c. hydraulic production
333 Water wheels, turbines and generators.
334 Accessory electric equipment.
335 Miscellaneous power plant equipment.
d. other production
344 Generators.
345 Accessory electric equipment.
346 Miscellaneous power plant equipment.
Transmission Plant
353 Station equipment.
Distribution Plant
362 Station equipment.
[FR Doc. 2018-03707 Filed 3-5-18; 8:45 am]
BILLING CODE 6717-01-P
Office of the Federal Register, National Archives and Records Administration
Section
Rules and Regulations
Action
Final action.
Dates
This final action will become effective May 15, 2018.
Contact
Jomo Richardson (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-6281, [email protected] Mark Bennett (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8524, [email protected]